<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Selected Consolidated Financial Data


                                                   Year Ended December 31,                      
                                  1998         1997          1996         1995          1994
                                                        (in thousands)
INCOME STATEMENTS DATA:
<S>                            <C>          <C>           <C>           <C>           <C>   
  Operating Revenues           $1,405,794   $1,339,232    $1,328,493    $1,283,157    $1,251,309
  Operating Expenses            1,239,787    1,131,444     1,108,076     1,077,434     1,029,340
  Operating Income                166,007      207,788       220,417       205,723       221,969
  Nonoperating Income (Loss)         (839)       4,415         2,729         6,272         7,428
  Income Before Interest
    Charges                       165,168      212,203       223,146       211,995       229,397
  Interest Charges                 68,540       65,463        65,993        70,903        71,895
  Net Income                       96,628      146,740       157,153       141,092       157,502
  Preferred Stock Dividend
    Requirements                    4,824        5,736        10,681        11,791        11,681
  Earnings Applicable to
    Common Stock               $   91,804   $  141,004    $  146,472    $  129,301    $  145,821

                                                   Year Ended December 31,                      
                                  1998         1997          1996         1995          1994
                                                        (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant       $4,631,848   $4,514,497    $4,377,669    $4,319,564    $4,269,306
  Accumulated Depreciation
    and Amortization            2,081,355    1,973,937     1,861,893     1,751,965     1,659,940
  Net Electric Utility Plant   $2,550,493   $2,540,560    $2,515,776    $2,567,599    $2,609,366

  Total Assets                 $4,148,523   $3,967,798    $3,897,484    $3,928,337    $3,878,035

  Common Stock and Paid-in
    Capital                    $  789,189   $  789,056    $  787,856    $  787,686    $  790,234
  Retained Earnings               253,154      278,814       269,071       235,107       216,658
  Total Common Shareholder's 
    Equity                     $1,042,343   $1,067,870    $1,056,927    $1,022,793    $1,006,892
                         
  Cumulative Preferred Stock:                     
    Not Subject to Mandatory
      Redemption               $    9,273   $    9,435    $   21,977    $   52,000    $   52,000
    Subject to Mandatory
      Redemption (a)               68,445       68,445       135,000       135,000       135,000
      Total Cumulative
        Preferred Stock        $   77,718   $   77,880    $  156,977    $  187,000    $  187,000

  Long-term Debt (a)           $1,175,789   $1,049,237    $1,042,104    $1,040,101    $1,069,887

  Obligations Under Capital
    Leases (a)                 $  186,427   $  195,227    $  130,965    $  142,506    $  152,589

  Total Capitalization
    and Liabilities            $4,148,523   $3,967,798    $3,897,484    $3,928,337    $3,878,035
                  
(a) Including portion due within one year.
</TABLE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION


   This discussion includes forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934. 
These forward-looking statements reflect assumptions, and involve
a number of risks and uncertainties.  Among the factors that could
cause actual results to differ materially from forward looking
statements are: electric load and customer growth; abnormal weather
conditions; available sources and costs of fuels; availability of
generating capacity; the speed and degree to which competition is
introduced to the power generation business, the structure and
timing of a competitive market and its impact on energy prices or
fixed rates; the ability to recover stranded costs in connection
with possible deregulation of generation; new legislation and
government regulations; the ability of the Company to successfully
control its costs; the economic climate and growth in our service
territory; unforeseen events affecting the Company's nuclear plant
which is on an extended safety related shutdown; unforeseen
problems or failures related to Year 2000 readiness of computer
software and hardware; inflationary trends; electricity  market
prices; interest rates; and other risks and unforeseen events. 
This discussion contains a "Year 2000 Readiness Disclosure" within
the meaning of the Year 2000 Information and Readiness Disclosure
Act.

   Indiana Michigan Power Company (the Company) is a wholly-owned
subsidiary of American Electric Power Company, Inc. (AEP Co.,
Inc.), a public utility holding company.  The Company is engaged in
the generation, purchase, sale, transmission and distribution of
electric power to 554,000 retail customers in its service territory
in northern and eastern Indiana and a portion of southwestern
Michigan and conducts business as American Electric Power (AEP). 
The Company supplies electric power to the AEP System Power Pool
(AEP Power Pool) and shares the revenues and costs of AEP Power
Pool wholesale sales to utility systems and power marketers. The
Company also sells wholesale power to municipalities and electric
cooperatives.  As a member of the AEP Power Pool and a signatory
company to the AEP System Transmission Equalization Agreement, the
Company's generation and transmission facilities are operated in
conjunction with the facilities of certain other affiliated
utilities as an integrated utility system.

Results of Operations

   Although operating revenues increased $67 million or 5% in 1998
and $11 million or 1% in 1997, net income decreased in both years. 
Net income declined $50 million or 34% in 1998 due to increased
purchased power and maintenance expense related to an extended
outage of the Company's two unit Donald C. Cook Nuclear Plant (Cook
Plant) which was shutdown in September 1997 and losses on certain
non-regulated energy trades outside of the AEP Power Pool's
traditional marketing area.  The 1997 decline of $10 million or 7%
resulted from increases in purchased power and other operation
expenses due in part to the nuclear plant outage.

Operating Revenues Increase

   Operating revenues increased 5% in 1998 following a 1% increase
in 1997.  The increases in operating revenues in 1998 and 1997 can
be attributed mainly to increased retail revenues.  The following
analyzes the changes in operating revenues:

                                      Increase (Decrease)
                                      From Previous Year       
(Dollars in Millions)                  1998           1997     
                                  Amount    %    Amount     %
Retail:
   Residential                    $ 26.4         $  4.3 
   Commercial                       26.1           10.3
   Industrial                       38.1           19.4
   Other                             0.4             - 
                                    91.0   9.6     34.0    3.7 

Wholesale                          (40.6)(11.2)   (29.1)  (7.4)

Transmission                        13.4  83.2      4.3   35.9

Miscellaneous                        2.8  27.6      1.5   18.6

     Total                        $ 66.6   5.0   $ 10.7    0.8

   Revenues from retail customers increased in 1998 due to the
accrual of revenues under fuel adjustment clauses for the increased
cost of replacement power and increased fossil fuel usage
necessitated by the extended outage of the Company's two nuclear
units and a 3% increase in sales.  The increase in retail revenues
in 1997 resulted from the accruals of revenues to be recovered
under power supply recovery mechanisms.  Under the retail
jurisdictional fuel clauses, revenues are accrued for the
unrecovered cost of fuel in both retail jurisdictions and for
replacement power costs in the Michigan jurisdiction until approved
for billing.

   The Company as part of the AEP System shares costs and benefits
of the System's generating facilities through the AEP Power Pool. 
The cost of the System's generating capacity is allocated among the
AEP Power Pool members, based on their relative peak demands and
generating reserves through the payment or receipt of capacity
charges and credits.  AEP Power Pool members are also compensated
for the out-of-pocket costs of energy delivered to the AEP Power
Pool and charged for energy received from the AEP Power Pool.

   The AEP Power Pool calculates each Company's prior twelve month
peak demand relative to the total peak demand of all member
companies as a basis for sharing revenues and costs.  The result of
this calculation is each Company's member load ratio (MLR) which
determines each Company's percentage share of revenues or costs. 
During 1998 the Company's MLR increased resulting in the Company
being allocated a larger share of wholesale revenues and expenses
from the AEP Power Pool.

   In 1997 management decided to develop a power marketing and
trading business.  The power marketing and trading business is
conducted by the AEP Power Pool and its revenues and expenses are
allocated to AEP Power Pool members based on MLR.

   Wholesale revenues declined in 1998 due to a decline in sales
to the AEP Power Pool reflecting the unavailability of the nuclear
units.  The decline was partially offset by the Company's share of
increased power marketing sales and trading activities.  A decrease
in sales to the AEP Power Pool due mainly to the outage of Cook
Plant is also the primary reason for the decline in wholesale
revenues in 1997.

Operating Expenses Increase

   Total operating expenses increased 10% in 1998 and 2% in 1997
primarily due to an increase in power purchases.  The changes in
operating expenses were:
                               Increase (Decrease)
                               From Previous Year    
(dollars in millions)           1998           1997  
                         Amount    %    Amount     % 

Fuel                     $(53.8) (23.8) $(9.8)   (4.2)
Purchased Power           133.3   80.9   26.1    18.8
Other Operation            13.1    3.9   23.6     7.6
Maintenance                39.8   33.8    2.5     2.2
Depreciation and
 Amortization               4.3    3.1    0.4     0.3
Amortization of Rockport
 Plant Unit 1 Phase-in
 Plan Deferrals           (11.9)(100.0)  (3.8)  (24.1)
Taxes Other Than
 Federal Income Taxes       2.6    4.1   (8.8)  (11.9)
Federal Income Taxes      (19.1) (27.0)  (6.8)   (8.8)
    Total                $108.3    9.6  $23.4     2.1

   The decrease in fuel expense in 1998 and 1997 reflects the
decrease in nuclear generation as both nuclear units were
unavailable from September 1997 through the end of 1998.  See Cook
Nuclear Plant Shutdown discussed below.

   Purchased power expense increased significantly in 1998 and
1997 due to increased purchases from the AEP Power Pool and the
Company's MLR share of increased purchases of electricity by the
AEP Power Pool.  The purchases replace power usually generated by
the unavailable nuclear units and supply the electricity for the
AEP Power Pool's marketing sales.


   The increases in other operation and maintenance expenses in
1998 were due to expenditures to prepare the nuclear units for
restart.  Other operation expense increased in 1997 due to the
effect of gains on the disposition of emission allowances recorded
in 1996 and higher administrative and general costs and
uncollectible accounts receivable expenses.

   The recovery period for Rockport Plant Unit 1 costs deferred
under rate phase-in plans in the Indiana and the Federal Energy
Regulatory Commission (FERC) jurisdictions ended in 1997 causing
the decrease in the amortization of phase-in plan deferrals.  The
deferred costs were amortized over a 10-year period commensurate
with their collection from customers.

   The decrease in taxes other than federal income taxes in 1997
was due to decreases in real and personal property taxes, Michigan
single business tax and Indiana supplemental income tax.

   Federal income taxes attributable to operations decreased in
1998 and 1997 due to decreases in pre-tax operating income. 

Nonoperating Income

   The decline in nonoperating income is due to losses in 1998
from non-regulated electricity trading activities.  These trading
activities are for forward electricity sales and purchases outside
of the AEP Power Pool's traditional marketing area and also include
electricity derivatives such as options, swaps, etc.  Open trades
are marked-to-market and recorded in nonoperating income.

Business Outlook

   The most significant factors affecting the Company's future
earnings are the restart of the Cook Plant units (discussed below
under Cook Nuclear Plant Shutdown) and the ability to recover costs
as the electric generating business becomes more competitive.  The
introduction of competition and customer choice for retail
customers in the Company's service territory has been slow and
continues at a deliberate pace as legislators and regulatory
officials recognize the complexity of the issues.  Federal
legislation has been proposed to mandate competition and customer
choice at the retail level, and several states have introduced or
are considering similar legislation.  Certain states, including
California, instituted full customer choice in 1998.  The Michigan
Commission has started a program for certain utilities to phase-in
to competition with the objective of providing full customer choice
by 2002.  The Company has begun discussions with the Michigan
Commission and other interested parties to formulate a plan.  The
actions by the Michigan Commission were not mandated by legislation
and are subject to a number of uncertainties and it is not
presently possible to determine what impact if any the resolution
of these matters will have on the operations of the Company.  The
Company's Michigan jurisdiction accounts for 13% of total revenues. 
Indiana is considering legislative initiatives to move to customer
choice, although the timing is uncertain.  The Company supports
customer choice and is proactively involved in discussions at both
the state and federal levels regarding the best competitive market
structure and method to transition to a competitive marketplace.

   As the pricing of generation in the electric energy market
evolves from regulated cost-of-service ratemaking to market-based
rates, many complex issues must be resolved, including the recovery
of stranded costs.  Stranded costs are those costs above market
that potentially would not be recoverable in a competitive market. 
At the wholesale level recovery of stranded costs under certain
conditions was addressed by the FERC when it established rules for
open transmission access and competition in the wholesale markets. 
However, the issue of stranded cost is unresolved at the retail
level where it is much larger than it is at the wholesale level. 
The amount of stranded cost the Company could experience depends on
the timing and extent to which competition is introduced to its
generation business and the future market prices of electricity. 
The recovery of stranded cost is dependent on the terms of future
legislation and related regulatory proceedings.

   Under the provisions of Statement of Financial Accounting
Standards (SFAS) 71 "Accounting for the Effects of Certain Types of
Regulation," regulatory assets (deferred expenses) and regulatory
liabilities (deferred revenues) are included in the consolidated
balance sheets of regulated utilities in accordance with regulatory
actions to match expenses and revenues with cost-based rates in the
same accounting period.  In order to maintain net regulatory assets
on the balance sheet, SFAS 71 requires that rates charged to
customers be cost-based and provide for the recovery of deferred
expenses over future accounting periods.  In the event a portion of
the Company's business no longer meets the requirements of SFAS 71,
SFAS 101 "Accounting for the Discontinuance of Application of
Statement 71" requires that net regulatory assets be written off
for that portion of the business.  The provisions of SFAS 71 and
SFAS 101 never anticipated that deregulation would include an
extended transition period or that it could provide for recovery of
stranded costs during and after the transition period.  In 1997 the
Financial Accounting Standards Board's (FASB) Emerging Issues Task
Force (EITF) addressed such a situation with the consensus reached
on issue 97-4 that requires the application of SFAS 71 to a segment
of a regulated electric utility cease when that segment is subject
to a legislatively approved plan for competition or an enabling
rate order is issued containing sufficient detail for the utility
to reasonably determine what the plan would entail.  The EITF
indicated that the cessation of application of SFAS 71 would
require that regulatory assets and impaired plant be written off
unless they are recoverable in future rates.

   Although certain FERC orders provide for competition in the
firm wholesale market, that market is a relatively small part of
our business and most of our firm wholesale sales are still under
cost-of-service contracts.  As a result, the Company's generation
business is still cost-based regulated and should remain so for the
near future.  We believe that enabling state legislation should
provide for the recovery of any generation-related net regulatory
assets and other reasonable stranded costs from impaired generating
assets.  However, if in the future the Company's generation
business were to no longer be cost-based regulated and if it were
not possible to demonstrate probability of recovery of resultant
stranded costs including regulatory assets, results of operations,
cash flows and financial condition would be adversely affected.

Litigation

Corporate Owned Life Insurance

   The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns for the years 1991
to 1993 requested a ruling from their National Office that certain
interest deductions claimed by the Company relating to AEP's
corporate owned life insurance (COLI) program should not be
allowed.  As a result of a suit filed by the Company in United
States (US) District Court (discussed below) this request for
ruling was withdrawn by the IRS agents.  Adjustments have been or
will be proposed by the IRS disallowing COLI interest deductions
for taxable years 1991-96.  A disallowance of the COLI interest
deductions through December 31, 1998 would reduce earnings by
approximately $66 million (including interest). The Company has
made no provision for any possible adverse earnings impact from
this matter.

   In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991-97
to avoid the potential assessment by the IRS of any additional
above market rate interest on the contested amount.  The payments
to the IRS are included on the balance sheet in other property and
investments pending the resolution of this matter.  The Company
will seek refund, either administratively or through litigation, of
all amounts paid plus interest.  In order to resolve this issue
without further delay, on March 24, 1998, the Company filed suit
against the US in the US District Court for the Southern District
of Ohio.  Management believes that it has a meritorious position
and will vigorously pursue this lawsuit.  In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.

   The Company is involved in a number of other legal proceedings
and claims.  While we are unable to predict the outcome of such
litigation, it is not expected that the ultimate resolution of
these matters will have a material adverse effect on the results of
operations, cash flows and/or financial condition.

Cost Containment and Process Improvement

   Efforts continue to reduce the cost of products and services in
order to maintain competitiveness.  The accounting department
completed its consolidation of operations and the marketing
department completed its reorganization in 1998 producing cost
reductions.  In 1998 the Company reviewed its staffing levels for
power generation and energy delivery and developed plans to reduce
staff in 1999.  The cost of staff reductions planned for 1999 was
provided for in the fourth quarter of 1998.  Although cost savings
are expected to result from the power generation and energy
delivery reorganizations, the Company continues to incur expenses
related to investments in marketing and customer services and the
reengineering and improvement of business processes.

   During 1998, the Company completed installation of a new
unified customer service system which is designed to support
customer requests for service, billings, accounts receivable,
credit and collection functions.  On January 1, 1999, the Company's
new financial data base and PeopleSoft client server accounting and
purchasing software became operational.  The move to client server
business software and related online data bases will empower
employees to maximize the benefits of their personal computers and
will position them to better access the power of the Internet and
other new technologies.

Costs for Spent Nuclear Fuel and Decommissioning

   The Company, as the owner of the Cook Plant, like other nuclear
power plant owners, has a significant future financial commitment
to safely dispose of spent nuclear fuel (SNF) and decommission and
decontaminate the plant.  The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site
disposal of SNF and high-level radioactive waste.  By law we
participate in the Department of Energy's (DOE) SNF disposal
program which is described in Note 3 of the Notes to Consolidated
Financial Statements.  Since 1983 we have collected $272 million
from customers for the disposal of nuclear fuel consumed at the
Cook Plant.  Of these funds, $115 million has been deposited in
external trust funds to provide for the future disposal of SNF and
$157 million has been remitted to the DOE.  Under the provisions of
the Nuclear Waste Policy Act, collections from customers are to
provide the DOE with money to build a repository for SNF.  However,
in December 1996, the DOE notified the Company that it would be
unable to begin accepting SNF by the January 1998 deadline required
by law.

   As a result of DOE's failure to make sufficient progress toward
a permanent repository or otherwise assume responsibility for SNF,
the Company along with a number of unaffiliated utilities and
states filed suit in the US Court of Appeals for the District of
Columbia Circuit requesting, among other things, that the court
order DOE to meet its obligations under the law.  The court ordered
the parties to proceed with contractual remedies but declined to
order DOE to begin accepting SNF for disposal.  DOE estimates its
planned site for the nuclear waste will not be ready until 2010. 
In June 1998, the Company filed a complaint in the US Court of
Federal Claims seeking damages in excess of $150 million due to the
DOE's partial material breach of its unconditional contractual
deadline to begin disposing of SNF generated by the Cook Plant. 
Similar lawsuits have been filed by other utilities.  As long as
the delay in the availability of a government approved storage
repository for SNF continues, the cost of both temporary and
permanent storage will increase.

   The cost to decommission the Cook Plant is affected by both
Nuclear Regulatory Commission (NRC) regulations and the delayed SNF
disposal program.  Studies completed in 1997 estimate the cost to
decommission the Cook Plant ranges from $700 million to $1,152
million in 1997 dollars.  This estimate could escalate due to
continued uncertainty in the SNF disposal program and the length of
time that SNF may need to be stored at the plant site.  External
trust funds have been established and funded with amounts collected
from customers to decommission the plant.  At December 31, 1998,
the total decommissioning trust fund balance was $443 million which
includes earnings on the trust investments.  We will work with
regulators and customers to recover the remaining estimated cost of
decommissioning the Cook Plant.  However, future results of
operations, cash flows and possibly financial condition would be
adversely affected if the cost of SNF disposal and decommissioning
continue to increase and cannot be recovered from customers.

Cook Nuclear Plant Shutdown

   Management shut down both units of the Cook Plant in September
1997 due to questions, which arose during a NRC architect engineer
design inspection, regarding the operability of certain safety
systems.  The NRC issued a Confirmatory Action Letter in September
1997 requiring the Company to address the issues identified in the
letter.  We are working with the NRC to resolve the remaining open
issue in the letter.

   In April 1998 the NRC notified the Company that it had convened
a Restart Panel for Cook Plant.  A list of required restart
activities was provided by the NRC in July 1998 and in October the
NRC expanded the list.  In order to identify and resolve the issues
necessary to restart the Cook units, the Company is and will be 
meeting with the Panel on a regular basis, until the units are
returned to service.

   In January 1999 we announced that we will conduct additional
engineering reviews at the Cook Plant that will delay restart of
the units.  Previously, the units were scheduled to return to
service at the end of the first and second quarters of 1999.  The
decision to delay restart resulted from internal assessments that
indicated a need to conduct expanded system readiness reviews.  A
new restart schedule will be developed based on the results of the
expanded reviews and should be available in June 1999.  When
maintenance and other activities required for restart are complete,
the Company will seek concurrence from the NRC to return the Cook
Plant to service.  Until these additional reviews are completed,
management is unable to determine when the units will be returned
to service.

   One of the steps the Company has taken toward expediting the
restart of the Cook units is to augment its existing nuclear
generation management and staff with personnel experienced in
restarting unaffiliated companies' nuclear plants during NRC
supervised extended outages.

   The costs incurred in 1997 and 1998 for restart of the Cook
units were $6 million and $78 million, respectively, and were
recorded as operation and maintenance expense.  Reductions in other
operation and maintenance expenses partially offset these costs. 
Currently incremental restart expenses are approximately $12
million a month.

   In July 1998 the Company received an "adverse trend letter"
from the NRC indicating that NRC senior managers determined that
there had been a slow decline in performance at the Cook Plant
during the 18 month period preceding the letter.  The letter
indicated that the NRC will closely monitor efforts to address
issues at Cook Plant through additional inspection activities.  In
October 1998 the NRC issued the Company a Notice of Violation and
proposed a $500,000 civil penalty for alleged violations at the
Cook Plant discovered during five inspections conducted between
August 1997 and April 1998.  The penalty was paid.

   The cost of electricity supplied to retail customers rose due
to the outage of the two units since higher cost coal-fired
generation and coal based purchased power were substituted for low
cost nuclear generation.  The Indiana and Michigan retail
jurisdictional fuel cost recovery mechanisms permit the recovery,
subject to regulatory commission review and approval, of changes in
fuel costs including the fuel component of purchased power in the
Indiana jurisdiction and changes in replacement power in the
Michigan jurisdiction.  Under these fuel cost recovery mechanisms,
retail rates contain a fuel cost adjustment factor that reflects
estimated fuel costs for the period during which the factor will be
in effect subject to reconciliation to actual fuel costs in a
future proceeding.  When actual fuel costs exceed the estimated
costs reflected in the billing factor a regulatory asset is
recorded and revenues are accrued.  Therefore, a regulatory asset
has been recorded and revenues accrued in anticipation of the
future reconciliation and billing under the fuel cost recovery
mechanisms of the higher fuel costs to replace Cook energy during
the extended outage.  At December 31, 1998, the regulatory asset
was $65 million.

   The Indiana Utility Regulatory Commission (IURC) approved,
subject to future reconciliation or refund, agreements authorizing
the Company, during the billing months of July 1998 through March
1999, to include in rates a fuel cost adjustment factor less than
that requested.  The agreements provide the parties to the
proceedings with the opportunity to conduct discovery regarding
certain issues that were raised in the proceedings, including the
appropriateness of the recovery of replacement energy cost due to
the extended Cook Plant outage, in anticipation of resolving the
issues in a future fuel cost adjustment proceeding.

   On March 16, 1999 a settlement agreement was filed with the
IURC resolving all matters related to the reasonableness of fuel
costs and all outage issues during an extended outage of the Cook
Plant.  The settlement agreement, which is subject to IURC
approval, provides for, among other things, a credit of $55 million
to Indiana retail customers; authorization to defer any unrecovered
fuel revenues accrued between September 9, 1997 and December 31,
1999 including the $55 million; authorization to defer up  to $150
million of incremental operation and maintenance restart costs for
the Cook Plant above the base rate level incurred during 1999;
amortization of the fuel recoveries and restart cost deferrals over
a five-year period ending December 31, 2003; a freeze in base rates
though December 31, 2003; and a cap on fuel recovery charges
through March 1, 2004.  The $55 million credit will be refunded
through customer's bills  during the months of July, August and
September 1999.  If the IURC does not approve the settlement, the
issue of recovery of replacement energy costs would be resolved
through regulatory hearings.

   Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect
on results of operations, cash flows, and possibly financial
condition.

Environmental Concerns and Issues

   We take great pride in our efforts to economically produce and
deliver electricity while minimizing the impact on the environment. 
The Company has spent hundreds of millions of dollars to equip our
facilities with the latest economical clean air and water
technologies and to research new technologies.  We intend to
continue in a leadership role fostering economically prudent
efforts to protect and preserve the environment.

   By-products from the generation of electricity include
materials such as ash, slag, sludge, low-level radioactive waste
and SNF.  Coal combustion by-products are typically disposed of or
treated in captive disposal facilities or are beneficially
utilized.  In addition, our generating plants and transmission and
distribution facilities have used asbestos, polychlorinated
biphenyls (PCBs) and other hazardous and nonhazardous materials. 
The Company is currently incurring costs to safely dispose of such
substances.  Additional costs could be incurred to comply with new
laws and regulations if enacted.

   The Comprehensive Environmental Response, Compensation and
Liability Act (Superfund) addresses clean-up of hazardous
substances at disposal sites and authorized the US Environmental
Protection Agency (Federal EPA) to administer the clean-up
programs.  As of year-end 1998, the Company is currently involved
in litigation with respect to one site overseen by the Federal EPA,
and has been named by the Federal EPA as a potentially responsible
party (PRP) for two other sites.  There is one additional site for
which the Company has received an information request which could
lead to PRP designation.  Historically, the Company's liability has
been resolved for a number of sites with no significant effect on
results of operations and present estimates do not anticipate
material cleanup costs for identified sites for which we have been
declared a PRP.  However, if for reasons not currently identified
significant cleanup costs are incurred, results of operations, cash
flows and possibly financial condition would be adversely affected
unless the costs can be recovered from customers.

   On September 24, 1998, the administrator of Federal EPA signed
final rules which require reductions in nitrogen oxides (NOx)
emissions in 22 eastern states, including the states in which the
generating plants of the Company and its affiliates in the AEP
System are located.  The implementation of the final rules would be
achieved through the revision of state implementation plans (SIPs)
by September 1999.  SIPs are a procedural method used by each state
to comply with Federal EPA rules.  The final rules anticipate the
imposition of a NOx reduction on utility sources of approximately
85% below 1990 emission levels by the year 2003.  On October 30,
1998, a number of utilities, including the Company and the other
operating companies of the AEP System, filed a petition in the US
Court of Appeals for the District of Columbia Circuit seeking a
review of the final rules.

   Should the states fail to adopt the required revisions to their
SIPs within one year of the date the final rules were signed
(September 24, 1999), Federal EPA has proposed to implement a
federal plan to accomplish the NOx reductions.  Federal EPA also
proposed the approval of portions of petitions filed by eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources in upwind midwestern
states.  These reductions are substantially the same as those
required by the final NOx rules and could be adopted by Federal EPA
in the event the states fail to implement SIPs in accordance with
the final rules.

   Preliminary estimates indicate that compliance could result in
required capital expenditures of approximately $169 million. 
Compliance costs cannot be estimated with certainty and the actual
costs incurred to comply could be significantly different from this
preliminary estimate depending upon the compliance alternatives
selected to achieve reductions in NOx emissions.  Unless such costs
are recovered from customers, they would have a material adverse
effect on results of operations, cash flows and possibly financial
condition.

   At the Third Conference of the Parties to the United Nations
Framework Convention on Climate Change held in Kyoto, Japan in
December 1997 more than 160 countries, including the US, negotiated
a treaty requiring legally-binding reductions in emissions of
greenhouse gases, chiefly carbon dioxide, which many scientists
believe are contributing to global climate change.  The treaty,
which requires the advice and consent of the US Senate for
ratification, would require the US to reduce greenhouse gas
emissions seven percent below 1990 levels in the years 2008-2012. 
Although the US has agreed to the treaty and signed it on November
12, 1998, President Clinton has indicated that he will not submit
the treaty to the Senate for consideration until it contains
requirements for "meaningful participation by key developing
countries" and the rules, procedures, methodology and guidelines of
the treaty's market-based policy instruments, joint implementation
programs and compliance enforcement provisions have been
negotiated.  At the Fourth Conference of the Parties, held in
Buenos Aires, Argentina, in November 1998, the parties agreed to a
work plan to complete negotiations on outstanding issues with a
view toward approving them at the Sixth Conference of the Parties
to be held in December 2000.  We will continue to work with the
Administration and Congress to monitor the development of public
policy on this issue.

   If the Kyoto treaty is approved by Congress, the costs to
comply with the emission reductions required by the treaty are
expected to be substantial and would have a material adverse impact
on results of operations, cash flows and possibly financial
condition if not recovered from customers.

Financial Condition

   The Company issued $175 million principal amount of long-term
obligations in 1998 at interest rates ranging from 6.45% to 7.6%. 
The principal amount of long-term debt retirements, including
maturities, totaled $55 million at interest rates ranging from 7%
to 7.8%.  Our senior secured debt/first mortgage bond ratings are:
Moody's, Baa1; Standard & Poor's, A-; and Fitch, BBB+.

   Gross plant and property additions were $159 million in 1998
and $235 million in 1997.  Management estimates construction
expenditures for the next three years to be $366 million which
includes the replacement of the Cook Plant Unit 1 steam generators. 
The funds for construction of new facilities and improvement of
existing facilities can come from a combination of internally
generated funds, short-term and long-term borrowings, preferred
stock issuances and investments in common equity by the Company's
parent, American Electric Power Company, Inc. (AEP Co., Inc.) 
However, all of the construction expenditures for the next three
years are expected to be financed with internally generated funds.

   When necessary the Company generally issues short-term debt to
provide for interim financing of capital expenditures that exceed
internally generated funds.  At December 31, 1998, $763 million of
unused short-term lines of credit shared with other AEP System
companies were available.  Short-term debt borrowings are limited
by provisions of the Public Utility Holding Company Act of 1935 to
$300 million.  Generally periodic reductions of outstanding short-term
debt are made through issuances of long-term debt and
additional capital contributions by the parent company.

   The Company's earnings coverage presently exceeds all minimum
coverage requirements for the issuance of mortgage bonds and
preferred stock.  The minimum coverage ratios are 2.0 for mortgage
bonds and 1.5 for preferred stock.  At December 31, 1998, the
mortgage bond and preferred stock coverage ratios were 6.39 and
2.08, respectively.

   The Company is committed under unit power agreements to
purchase all of an affiliate's share, 50% of the 2,600 megawatt
(mw) Rockport Plant capacity, unless it is sold to other utilities. 
The affiliate has a long-term unit power agreement for the sale of
455 mw to an unaffiliated utility.  Revenues received under this
agreement (which expires at the end of 1999) were $70 million in
1998.  An agreement between the affiliate which owns Rockport Plant
and another affiliate provides for the sale of 390 mw of capacity
to that affiliate through 2004.

Market Risks

   The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates.  The trading of electricity and related financial
derivative instruments through the AEP Power Pool on the Company's
behalf exposes the Company to market risk.  Market risk represents
the risk of loss that may impact the Company due to adverse changes
in electricity commodity market prices and rates.  In 1998 the  AEP
Power Pool substantially increased the volume of its wholesale
power marketing and trading activities.  Various policies and
procedures have been established to manage market risk exposures
including the use of a risk measurement model utilizing Value at
Risk (VaR).  Throughout the year ending December 31, 1998, the
Company's share of the highest, lowest and average quarterly VaR in
the wholesale trading portfolio was less than $2 million at a 95%
confidence level with a holding period of three business days. The
AEP Power Pool uses the variance-covariance method for calculating
VaR based on three months of daily prices.  Based on this VaR
analysis, at December 31, 1998 a near term change in commodity
prices is not expected to have a material effect on the Company's
results of operations, cash flows or financial condition.

   The Company is exposed to changes in interest rates primarily
due to short-term and long-term borrowings to fund its business
operations.  The debt portfolio has both fixed and variable
interest rates with terms from one day to forty years and an
average duration of six years at December 31, 1998.  The Company
measures interest rate market risk exposure utilizing a VaR model. 
The model is based on the Monte Carlo method of simulated price
movements with a 95% confidence level and a one year holding
period.  The volatilities and correlations are based on three years
of monthly prices.  The risk of potential loss in fair value
attributable to the Company's exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $102
million at December 31, 1998.  The Company would not expect to
liquidate its entire debt portfolio in a one year holding period. 
Therefore, a near term change in interest rates should not
materially affect results of operations or the consolidated
financial position of the Company.  Also since the Company's rates
are cost-based regulated, the risk of interest rate changes on debt
used to finance regulated operations is mitigated.

   Inflation affects the Company's cost of replacing utility plant
and the cost of operating and maintaining its plant.  The rate-making
process generally limits our recovery to the historical cost
of assets resulting in economic losses when the effects of
inflation are not recovered from customers on a timely basis. 
However, economic gains that result from the repayment of long-term
debt with inflated dollars partly offset such losses.

Other Matters

Computer Issue - Year 2000

   On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date.  In
addition, certain systems may fail to detect that the year 2000 is
a leap year.  Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Year 2000
ready programs.

   Readiness Program - Internally, the Company, through the AEP
System, is modifying or replacing its computer hardware and
software programs to minimize Year 2000-related failures and repair
such failures if they occur.  This includes both information
technology systems (IT), which are mainframe and client server
applications, and embedded logic systems (non-IT), such as process
controls for energy production and delivery.  Externally, the
problem is being addressed with entities that interact with the
Company, including suppliers, customers, creditors, financial
service organizations and other parties essential to the Company's
operations.  In the course of the external evaluation, the Company
has sought written assurances from third parties regarding their
state of Year 2000 readiness.

   Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system. 
The Company, along with other electric utilities in North America,
regularly submits information to the North American Electric
Reliability Council (NERC) as part of NERC's Year 2000 readiness
program.  NERC then publicly reports summary information to the DOE
regarding the Year 2000 readiness of electric utilities.  In 1999
AEP plans to participate in two NERC-sponsored coordinated electric
industry Year 2000 readiness drills.

   The second NERC report, dated January 11, 1999 and entitled:
Preparing the Electric Power Systems of North American for
Transition to the Year 2000 - A Status Report and Work Plan, Fourth
Quarter 1998, states that: "With more than 44% of mission critical
components tested through November 30, 1998, findings continue to
indicate that transition through critical Year 2000 (Y2K) rollover
dates is expected to have minimal impact on electric system
operations in North America."  The Company continues to set a
target date of June 30, 1999 for having all mission critical and
high priority systems and components Y2K ready.

   Through the Electric Power Research Institute, an electric
industry-wide effort has been established to deal with Year 2000
problems affecting embedded systems.  Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.

   The state regulatory commissions in the Company's service
territory are also reviewing the Year 2000 readiness of the
Company.

   Company's State of Readiness - Work has been prioritized in
accordance with business risk.  The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy, and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.

<PAGE>
   The following chart shows our progress toward becoming ready
for the Year 2000 as of December 31, 1998:
                                  IT SYSTEMS              NON-IT  SYSTEMS
                          COMPLETION                 COMPLETION
                          DATE/ESTIMATED   PERCENT   DATE/ESTIMATED   PERCENT
YEAR 2000 PROJECT PHASES  COMPLETION DATE  COMPLETE  COMPLETION DATE  COMPLETE

Launch: Initiation of       2/24/1998        100%      5/31/1998       100%
the Year 2000 activities
within the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.

Inventory and Assessment: 
Identifying all Company     7/31/1998        100%       2/15/1999      99%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.

Remediation/Testing: The
process of modifying,       6/30/1999     Mainframe:    6/30/1999      37%
replacing or retiring                     70%
those mission critical and                        
high priority digital-based
systems with problems                     Client
processing dates past the                 Server:
Year 2000. Testing these                  18%
systems to ensure that after             
modifications have been                  
implemented correct date                 
processing occurs and full
functionality has been maintained.

   Costs to Address the Company's Year 2000 Issues - Through
December 31, 1998, the Company has spent $4 million on the Year
2000 project and, estimates spending an additional $6 million to $9
million to achieve Year 2000 readiness.  Most Year 2000 costs are
for software modifications, IT consultants and salaries and are
expensed; however, in certain cases the Company has acquired
hardware that was capitalized.  The Company intends to fund these
expenditures through internal sources.  Although significant, the
cost of becoming Year 2000 compliant is not expected to have a
material impact on the Company's results of operations, cash flows
or financial condition.

   Risks of the Company's Year 2000 Issues - The applications
posing the greatest business risk to the Company's operations
should they experience Y2K problems are:

   * Automated power generation, transmission and distribution systems
   * Telecommunications systems
   * Energy trading systems
   * Time-in-use, demand and remote metering systems for
     commercial and industrial customers and
   * Work management and billing systems.

   The potential problems related to erroneous processing by, or
failure of, these systems are:

   * Power service interruptions to customers
   * Interrupted revenue data gathering and collection
   * Poor customer relations resulting from delayed billing and
     settlement.

   In addition, although as discussed relationships with third
parties, such as suppliers, customers and other electric utilities,
are being monitored, these third parties nonetheless represent a
risk that cannot be assessed with precision or controlled with
certainty.

   Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others not affiliated with the AEP System, fail for
critical applications, Year 2000-related issues may materially
adversely affect the Company.

Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Year
2000 related failures, we have established a draft Year 2000
contingency plan and submitted it to the East Central Area
Reliability Council in December 1998 as part of NERC's review of
regional and individual electric utility contingency plans in 1999. 
NERC's target date is June 1999 for the completion of this
contingency plan.  In addition, the Company intends to establish
contingency plans for its business units to address alternatives if
Year 2000 related failures occur.  Contingency plans will be
developed by the end of 1999.  The Company's plans build upon the
disaster recovery, system restoration, and contingency planning
that we have had in place.

New Accounting Standards

   In 1997 the FASB issued SFAS 130 "Reporting Comprehensive
Income" and SFAS 131 "Disclosures About Segments of an Enterprise
and Related Information." SFAS 130 establishes the standards for
reporting and displaying components of "comprehensive income,"
which is the total of net income and all transactions not included
in net income affecting equity except those with shareholders.  The
Company adopted SFAS 130 in the first quarter of 1998.  For 1998
there were no material differences between net income and
comprehensive income.

   SFAS 131 initiates standards for annual and interim financial
statements to report operating segments of a business for which
separate financial information is available and regularly evaluated
by the chief operating decision maker in allocating resources and
reviewing performance.  Information about products and services and
geographic areas is to be reported at an enterprise-level instead
of by segment.  SFAS 131 was required to be adopted by the Company
for the year ended December 31, 1998 with restatement of prior
period comparative information.  Adoption of SFAS 131 did not have
any effect on results of operations, cash flows or financial
condition.

   In the first quarter of 1998 the Company adopted the American
Institute of Certified Public Accountants' (AICPA) Statement of
Position (SOP) 98-1, "Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use". The SOP requires the
capitalization and amortization of certain costs of acquiring or
developing internal use computer software.  Previously the Company
expensed all software acquisition and development costs.  The SOP
had to be adopted at the beginning of a fiscal year with no
restatement or retroactive adjustment of prior periods.  The
adoption of the SOP effective January 1, 1998 did not have a
material effect on results of operations, cash flows or financial
condition.

   In February 1998, the FASB issued SFAS 132 "Employers'
Disclosure about Pensions and Other Postretirement Benefits"  which
revised employers' disclosures about pensions and other
postretirement benefit plans and suggested that the disclosure be
combined.  It did not change the measurement or recognition
requirements for postretirement benefit accounting.  The adoption
of SFAS 132 did not have an effect on results of operations, cash
flows or financial condition.

   EITF 98-10 "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities" was issued in November 1998 to
address the application of mark-to-market accounting for energy
trading contracts.  Under the provisions of this standard, which
must be adopted by the Company in January 1999, energy trading
contracts can no longer be accounted for on a settlement basis. 
Instead they are to be marked-to-market.  Initial adoption of EITF
98-10 is not expected to have a significant impact on results of
operations, cash flows, or financial condition.

   The FASB issued SFAS 133 "Accounting for Derivative Instruments
and Hedging Activities" in June 1998.  SFAS 133 establishes
accounting and reporting standards for derivative instruments.  It
requires that all derivatives be recognized as either an asset or
a liability and measured at fair value in the financial statements. 
If certain conditions are met a derivative may be designated as a
hedge of possible changes in fair value of an asset, liability or
firm commitment; variable cash flows of forecasted transactions; or
foreign currency exposure.  The accounting/reporting for changes in
a derivative's fair value (gains and losses) depend on the intended
use and resulting designation of the derivative.  Management is
currently studying the provisions of SFAS 133 to determine the
impact, of its adoption on January 1, 2000, on results of
operations, cash flows and financial condition.

   In April 1998 the AICPA issued SOP 98-5 "Reporting on the Costs
of Start-up Activities".  The SOP clarifies the accounting and
reporting for one time start-up activities and organization costs,
requiring that they be expensed as incurred.  The adoption of this
standard in January 1999 is not expected to have a material effect
on results of operations, cash flows or financial condition.
<PAGE>
INDEPENDENT AUDITORS' REPORT






To the Shareholders and Board of
Directors of Indiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets of
Indiana Michigan Power Company and its subsidiaries as of December
31, 1998 and 1997, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1998.  These financial
statements are the responsibility of the Company's management.  Our
responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with generally accepted
auditing standards.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements.  An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation.  We believe that our audits
provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of Indiana
Michigan Power Company and its subsidiaries as of December 31, 1998
and 1997, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 1998
in conformity with generally accepted accounting principles.


/s/ Deloitte & Touche LLP


DELOITTE & TOUCHE LLP
Columbus, Ohio
February 23, 1999
(March 16, 1999 as to Note 4)

<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income


                                                                 Year Ended December 31,       
                                                            1998           1997         1996
                                                                      (in thousands)
<S>                                                      <C>            <C>          <C>
OPERATING REVENUES                                       $1,405,794     $1,339,232   $1,328,493

OPERATING EXPENSES:
  Fuel                                                      172,592        226,402      236,237
  Purchased Power                                           298,046        164,775      138,687
  Other Operation                                           347,207        334,115      310,513
  Maintenance                                               157,593        117,780      115,300
  Depreciation and Amortization                             145,112        140,812      140,437
  Amortization of Rockport Plant Unit 1
   Phase-in Plan Deferrals                                     -            11,871       15,644
  Taxes Other Than Federal Income Taxes                      67,592         64,945       73,729
  Federal Income Taxes                                       51,645         70,744       77,529
           Total Operating Expenses                       1,239,787      1,131,444    1,108,076

OPERATING INCOME                                            166,007        207,788      220,417

NONOPERATING INCOME (LOSS)                                     (839)         4,415        2,729

INCOME BEFORE INTEREST CHARGES                              165,168        212,203      223,146

INTEREST CHARGES                                             68,540         65,463       65,993

NET INCOME                                                   96,628        146,740      157,153

PREFERRED STOCK DIVIDEND REQUIREMENTS                         4,824          5,736       10,681

EARNINGS APPLICABLE TO COMMON STOCK                      $   91,804     $  141,004   $  146,472
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets


                                                                           December 31,       
                                                                       1998            1997
                                                                          (in thousands)
ASSETS
<S>                                                                 <C>             <C>
ELECTRIC UTILITY PLANT:
 Production                                                         $2,556,732      $2,545,484
 Transmission                                                          913,252         908,736
 Distribution                                                          768,803         737,902
 General (including nuclear fuel)                                      236,650         233,888
 Construction Work in Progress                                         156,411          88,487
         Total Electric Utility Plant                                4,631,848       4,514,497
 Accumulated Depreciation and Amortization                           2,081,355       1,973,937
         NET ELECTRIC UTILITY PLANT                                  2,550,493       2,540,560


NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR 
 FUEL DISPOSAL TRUST FUNDS                                             648,307         566,390 


OTHER PROPERTY AND INVESTMENTS                                         197,368         156,228



CURRENT ASSETS:
 Cash and Cash Equivalents                                              12,465           5,860
 Accounts Receivable:
  Customers                                                             94,502         107,087
  Affiliated Companies                                                  19,528          15,662
  Miscellaneous                                                         18,743          14,561
  Allowance for Uncollectible Accounts                                  (2,027)         (1,188)
 Fuel - at average cost                                                 20,857          17,182
 Materials and Supplies - at average cost                               78,009          78,701
 Accrued Utility Revenues                                               37,277          30,521
 Prepayments and Other                                                  18,953           4,685
         TOTAL CURRENT ASSETS                                          298,307         273,071


REGULATORY ASSETS                                                      421,475         400,489


DEFERRED CHARGES                                                        32,573          31,060


           TOTAL                                                    $4,148,523      $3,967,798
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES


                                                                          December 31,        
                                                                      1998            1997
                                                                         (in thousands)
<S>                                                                <C>             <C>
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
 Common Stock - No Par Value:
   Authorized - 2,500,000 Shares
   Outstanding - 1,400,000 Shares                                  $   56,584      $   56,584
   Paid-in Capital                                                    732,605         732,472
   Retained Earnings                                                  253,154         278,814
           Total Common Shareholder's Equity                        1,042,343       1,067,870
   Cumulative Preferred Stock:
     Not Subject to Mandatory Redemption                                9,273           9,435
     Subject to Mandatory Redemption                                   68,445          68,445
   Long-term Debt                                                   1,140,789       1,014,237
           TOTAL CAPITALIZATION                                     2,260,850       2,159,987

OTHER NONCURRENT LIABILITIES:
 Nuclear Decommissioning                                              445,934         381,016
 Other                                                                240,320         232,667
           TOTAL OTHER NONCURRENT LIABILITIES                         686,254         613,683

CURRENT LIABILITIES:
 Long-term Debt Due Within One Year                                    35,000          35,000
 Short-term Debt                                                      108,700         119,600
 Accounts Payable - General                                            53,187          36,729
 Accounts Payable - Affiliated Companies                               37,647          31,665
 Taxes Accrued                                                         35,161          46,850
 Interest Accrued                                                      15,279          15,741
 Obligations Under Capital Leases                                       9,667          34,033
 Other                                                                 87,293          63,250
           TOTAL CURRENT LIABILITIES                                  381,934         382,868

DEFERRED INCOME TAXES                                                 559,288         559,708

DEFERRED INVESTMENT TAX CREDITS                                       129,779         138,045

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2                                                88,712          92,419

DEFERRED CREDITS                                                       41,706          21,088

COMMITMENTS AND CONTINGENCIES (Note 3)

             TOTAL                                                 $4,148,523      $3,967,798
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows


                                                                  Year Ended December 31,     
                                                           1998          1997          1996
                                                                    (in thousands)
<S>                                                      <C>           <C>           <C>
OPERATING ACTIVITIES:
  Net Income                                             $  96,628     $ 146,740     $ 157,153 
  Adjustments for Noncash Items:
   Depreciation and Amortization                           149,209       148,630       148,123
   Amortization of Rockport Plant Unit 1
    Phase-in Plan Deferrals                                   -           11,871        15,644 
   Amortization (Deferral) of Incremental Nuclear
    Refueling Outage Expenses (net)                         14,142       (15,967)        7,662
   Deferred Federal Income Taxes                            17,905         3,922       (24,687)
   Deferred Investment Tax Credits                          (8,266)       (8,428)       (8,729)
   Over (Under)-recovery of Fuel and Purchased Power       (46,846)      (22,812)       12,477
  Changes in Certain Current Assets and Liabilities:
   Accounts Receivable (net)                                 5,376       (10,456)      (10,235)
   Fuel, Materials and Supplies                             (2,983)        5,168           903 
   Accrued Utility Revenues                                 (6,756)        7,774         5,642 
   Accounts Payable                                         22,440         6,502         1,186 
   Taxes Accrued                                           (11,689)      (18,550)       (6,296)
  Payment of Disputed Tax and Interest Related to COLI     (53,628)         -             -
  Other (net)                                               (8,176)        5,817        (4,502)
     Net Cash Flows From Operating Activities              167,356       260,211       294,341

INVESTING ACTIVITIES:
  Construction Expenditures                               (147,627)     (122,360)      (95,046)
  Proceeds from Sales of Property and Other                  4,419         2,016         2,776
    Net Cash Flows Used For Investing Activities          (143,208)     (120,344)      (92,270)

FINANCING ACTIVITIES:
 Issuance of Long-term Debt                                170,675        47,728        38,579
 Retirement of Cumulative Preferred Stock                     (120)      (78,877)      (30,568)
 Retirement of Long-term Debt                              (55,000)      (50,000)      (46,091)
 Change in Short-term Debt (net)                           (10,900)       76,100       (46,475)
 Dividends Paid on Common Stock                           (117,464)     (131,260)     (112,508)
 Dividends Paid on Cumulative Preferred Stock               (4,734)       (5,931)      (10,498)
    Net Cash Flows Used For Financing Activities           (17,543)     (142,240)     (207,561)

Net Increase (Decrease) in Cash and Cash Equivalents         6,605        (2,373)       (5,490)
Cash and Cash Equivalents January 1                          5,860         8,233        13,723
Cash and Cash Equivalents December 31                    $  12,465     $   5,860     $   8,233
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings


                                                                 Year Ended December 31,       
                                                         1998            1997            1996
                                                                    (in thousands)
<S>                                                    <C>             <C>             <C>
Retained Earnings January 1                            $278,814        $269,071        $235,107
Net Income                                               96,628         146,740         157,153
                                                        375,442         415,811         392,260
Deductions:
 Cash Dividends Declared:
   Common Stock                                         117,464         131,260         112,508
   Cumulative Preferred Stock:
     4-1/8% Series                                          247             249             495
     4.56%  Series                                           67              88             273
     4.12%  Series                                           79              80             165
     5.90%  Series                                          985             985           2,360
     6-1/4% Series                                        1,266           1,266           1,875
     6.30%  Series                                          834             834           2,205
     6-7/8% Series                                        1,255           1,255           2,063
     7.08%  Series                                         -               -                531
           Total Cash Dividends Declared                122,197         136,017         122,475
  Capital Stock Expense                                      91             980             714
            Total Deductions                            122,288         136,997         123,189

Retained Earnings December 31                          $253,154        $278,814        $269,071
</TABLE
See Notes to Consolidated Financial Statements.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. SIGNIFICANT ACCOUNTING POLICIES:

Organization

   Indiana Michigan Power Company (the Company or I&M) is a
wholly-owned subsidiary of American Electric Power Company, Inc.
(AEP Co., Inc.), a public utility holding company.  The Company is
engaged in the generation, purchase, sale, transmission and
distribution of electric power to 554,000 retail customers in its
service territory in northern and eastern Indiana and a portion of
southwestern Michigan and conducts business as American Electric
Power (AEP).  The Company supplies electric power to the AEP System
Power Pool (Power Pool) and shares the revenues and costs of Power
Pool wholesale sales to utility systems and power marketers. The
Company also sells wholesale power to municipalities and electric
cooperatives.  As a member of the Power Pool and a signatory
company to the AEP System Transmission Equalization Agreement, the
Company's generation and transmission facilities are operated in
conjunction with the facilities of certain other affiliated
utilities as an integrated utility system.

   The Company has two wholly-owned subsidiaries, that were
formerly engaged in coal-mining operations which are consolidated
in these financial statements, Blackhawk Coal Company and Price
River Coal Company.  Blackhawk Coal Company currently leases and
subleases portions of its Utah coal rights, land and related mining
equipment to unaffiliated companies.  Price River Coal Company,
which owns no land or mineral rights, is inactive.  The Company's
River Transportation Division provided barging services to
affiliated and unaffiliated companies.

Regulation

   As a subsidiary of AEP Co., Inc., the Company is subject to the
regulation of the Securities and Exchange Commission (SEC) under
the Public Utility Holding Company Act of 1935 (1935 Act).  Retail
rates are regulated by the Indiana Utility Regulatory Commission
(IURC) and the Michigan Public Service Commission (MPSC).  The
Federal Energy Regulatory Commission (FERC) regulates wholesale
rates.

Principles of Consolidation

   The consolidated financial statements include the revenues,
expenses, cash flows, assets, liabilities and equity of I&M and its
wholly-owned subsidiaries.  Significant intercompany items are
eliminated in consolidation.

Basis of Accounting

   As a cost-based rate-regulated entity, I&M's financial
statements reflect the actions of regulators that result in the
recognition of revenues and expenses in different time periods than
enterprises that are not rate regulated.  In accordance with
Statement of Financial Accounting Standards (SFAS) 71, "Accounting
for the Effects of Certain Types of Regulation," regulatory assets
(deferred expenses) and regulatory liabilities (deferred income)
are recorded to reflect the economic effects of regulation and to
match expenses with regulated revenues.

Use of Estimates

   The preparation of these financial statements in conformity
with generally accepted accounting principles requires in certain
instances the use of estimates.  Actual results could differ from
those estimates.

Utility Plant

   Electric utility plant is stated  at original cost and is
generally subject to first mortgage liens.  Additions, major
replacements and betterments are added to the plant accounts. 
Retirements of plant are deducted from the electric utility plant
in service account and are deducted from accumulated depreciation
together with associated removal costs, net of salvage.  The costs
of labor, materials and overheads incurred to operate and maintain
utility plant are included in operating expenses.

Allowance for Funds Used During Construction (AFUDC)

   AFUDC is a noncash nonoperating income item that is capitalized
and recovered through depreciation over the service life of utility
plant.  It represents the estimated cost of borrowed and equity
funds used to finance construction projects.  The amounts of AFUDC
for 1998, 1997 and 1996 were not significant.

Depreciation and Amortization

   Depreciation of electric utility plant is provided on a
straight-line basis over the estimated useful lives of utility
plant and is calculated largely through the use of composite rates
by functional class.  The annual composite depreciation rates for
1998, 1997 and 1996 are as follows:

Functional Class                              Annual Composite
of Property                                  Depreciation Rates  
                                           1998     1997     1996
Production:
  Steam-Nuclear                            3.4%     3.4%     3.4%
  Steam-Fossil-Fired                       4.4%     4.4%     4.4%
  Hydroelectric-Conventional               3.4%     3.2%     3.2%
Transmission                               1.9%     1.9%     1.9%
Distribution                               4.2%     4.2%     4.2%
General                                    3.8%     3.8%     3.8%



   Amounts for the demolition and removal of non-nuclear plant are
charged to the accumulated provision for depreciation and recovered
through depreciation charges included in rates.  The accounting and
rate-making treatment afforded nuclear decommissioning costs and
nuclear fuel disposal costs are discussed in Note 3.

Cash and Cash Equivalents

   Cash and cash equivalents include temporary cash investments
with original maturities of three months or less.

Operating Revenues and Fuel Costs

   Revenues include the accrual of electricity consumed but
unbilled at month-end as well as billed revenues.  Fuel costs are
matched with revenues in accordance with rate commission orders. 
Revenues are accrued related to unrecovered fuel in both state
retail jurisdictions and for replacement power costs in the
Michigan jurisdiction until approved for billing.  If the Company's
earnings exceed the allowed return in the Indiana jurisdiction, the
fuel clause mechanism provides for the refunding of the excess
earnings to ratepayers.  FERC wholesale jurisdictional fuel cost
changes are expensed and billed as incurred.

Derivative Financial Instruments

   During 1998, the AEP Power Pool substantially increased the
volume of its power marketing and trading transactions (trading
activities) in which the Company shares.  Trading activities
involve the sale of electricity under physical forward contracts at
fixed and variable prices and the trading of electricity contracts
including exchange traded futures and options and over-the-counter
options and swaps.  The majority of these transactions represent
physical forward contracts in the AEP System's traditional
marketing area and are typically settled by entering into
offsetting contracts.  The net revenues from these transactions are
included in operating revenues for ratemaking, accounting and
financial and regulatory reporting purposes.

   In addition the AEP Power Pool enters into transactions for the
purchase and sale of electricity options, futures and swaps, and
for the forward purchase and sale of electricity outside of the AEP
Power Pool's  traditional marketing area.  These non-regulated
trading activities are included in nonoperating income and
accounted for on a mark-to-market basis.  The unrealized mark-to-market 
gains and losses from such non-regulated trading activity
are reported as assets and liabilities, respectively.

   The Company enters into forward contracts to manage the
exposure to unfavorable changes in the cost of debt to be issued. 
These anticipatory debt instruments are entered into in order to
manage the change in interest rates between the time a debt
offering is initiated and the issuance of the debt (usually a
period of 60 days).  Any resultant gains or losses are deferred and
amortized over the life of the debt issuance.  There were no such
forward contracts outstanding at December 31, 1998 or 1997.

   See Note 7 - Financial Instruments, Credit and Risk Management
for further discussion.

Reclassification

   In the fourth quarter of 1998 the Company changed the
presentation of its trading activities from a gross basis
(purchases and sales reported separately) to a net basis (purchases
and sales are reported on a net basis as revenues).  This
reclassification had no impact on net income.  Certain prior year
amounts have been reclassified to conform to current year
presentation.  Such reclassifications had no impact on previously
reported net income.

Levelization of Nuclear Refueling Outage Costs

   Incremental operation and maintenance costs associated with
refueling outages at the Company's Donald C. Cook Nuclear Plant
(Cook Plant)  are deferred commensurate with their rate-making
treatment and amortized over the period beginning with the
commencement of an outage and ending with the beginning of the next
outage.

Income Taxes

   The Company follows the liability method of accounting for
income taxes as prescribed by SFAS 109, "Accounting for Income
Taxes."  Under the liability method, deferred income taxes are
provided for all temporary differences between the book cost and
tax basis of assets and liabilities which will result in a future
tax consequence.  Where the flow-through method of accounting for
temporary  differences is reflected in rates, deferred income taxes
are provided with related regulatory assets and liabilities in
accordance with SFAS 71.

Investment Tax Credits

   Investment tax credits have been accounted for under the flow-through
method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral
basis.  Investment tax credits that have been deferred are being
amortized over the life of regulated plant investment.

Debt and Preferred Stock

   Gains and losses from the reacquisition of debt are deferred as
regulatory assets and amortized over the remaining term of the
reacquired debt in accordance with rate-making treatment.  If the
debt is refinanced the reacquisition costs are deferred and
amortized over the term of the replacement debt commensurate with
their recovery in rates.

   Debt discount or premium and debt issuance expenses are
deferred and amortized over the term of the related debt, with the
amortization included in interest charges.

   Redemption premiums paid to reacquire preferred stock are
included in paid-in capital and amortized to retained earnings
commensurate with their recovery in rates.  The excess of par value
over the cost of preferred stock reacquired is credited to paid-in
capital and amortized to retained earnings.

Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds

   Securities held in trust funds for decommissioning nuclear
facilities and for the disposal of spent nuclear fuel (SNF) are
recorded at market value in accordance with SFAS 115, "Accounting
for Certain Investments in Debt and Equity Securities."  Securities
in the trust funds have been classified as available-for-sale due
to their long-term purpose.  Due to the rate-making process,
adjustments for unrealized gains and losses are not reported in
equity but result in adjustments to the liability account for the
nuclear decommissioning trust funds and to regulatory assets or 
liabilities for the SNF disposal trust funds.

Other Property and Investments

   Other property and investments are stated at cost.

Comprehensive Income

   There were no material differences between net income and
comprehensive income.


2. EFFECTS OF REGULATION AND PHASE-IN PLANS:

   In accordance with SFAS 71 the consolidated financial
statements include regulatory assets (deferred expenses) and
regulatory liabilities (deferred income) recorded in accordance
with regulatory actions in order to match expenses and revenues
from cost-based rates in the same accounting period.  Regulatory
assets are expected to be recovered in future periods through the
rate-making process and regulatory liabilities are expected to
reduce future cost recoveries.  Among other things, application of
SFAS 71 requires that the Company's regulated rates be cost-based
and recovery of regulatory assets must be probable.  Management has
reviewed the evidence currently available and concluded that the
Company continues to meet the requirements to apply SFAS 71.  In
the event a portion of the Company's business no longer met these
requirements, that is, its rates were no longer cost-based,
regulatory assets and liabilities would have to be written off for
that portion of the business and tangible assets would have to be
tested for possible impairment and if required an impairment loss
recorded unless the net regulatory assets and impairment losses are
recoverable as a stranded cost.

   Recognized regulatory assets and liabilities are comprised of
the following:
                                        December 31,  
                                     1998       1997
                                      (in thousands)
Regulatory Assets:
  Amounts Due From Customers for
    Future Income Taxes            $259,641   $277,966
  Unrecovered Fuel and
    Purchased Power                  65,308     18,462
  Department of Energy
    Decontamination and
    Decommissioning Assessment       38,898     42,648
  Nuclear Refueling
    Outage Cost Levelization         17,630     31,772
  Unamortized Loss On
    Reacquired Debt                  16,434     17,210
  Other                              23,564     12,431
    Total Regulatory Assets        $421,475   $400,489

Regulatory Liabilities:
  Deferred Investment Tax Credits  $129,779   $138,045
  Other*                             16,507      1,262
    Total Regulatory Liabilities   $146,286   $139,307

* Included in Deferred Credits on Consolidated Balance
  Sheets.

   The Rockport Plant consists of two 1,300 megawatt (mw) coal-fired 
units.  I&M and AEP Generating Company (AEGCo), an affiliate,
each own 50% of one unit (Rockport 1) and each lease a 50% interest
in the other unit (Rockport 2) from unaffiliated lessors under an
operating lease.  The gain on the sale and leaseback of Rockport 2
was deferred and is being amortized, with related taxes, over the
initial lease term which expires in 2022.

   At January 1, 1997 rate phase-in plan deferrals existed for the
Rockport Plant.  Rate phase-in plans in the Company's Indiana and
FERC jurisdictions provided for the recovery and straight-line
amortization of deferred Rockport Plant Unit 1 costs over ten years
beginning in 1987.  In 1997 the amortization and recovery of the
deferred Rockport Plant Unit 1 Phase-in Plan costs were completed. 
During the recovery period net income was unaffected by the
recovery of the phase-in deferrals.  Amortization was $11.9 million
in 1997 and $15.6 million in 1996.

<PAGE>
3. COMMITMENTS AND CONTINGENCIES:

Construction and Other Commitments

   Substantial construction commitments have been made to support
the Company's utility operations including the replacement of the
Cook Plant Unit 1 steam generators.  Such commitments do not
include any expenditures for new generating capacity.  Construction
program expenditures for 1999-2001 are estimated to be $366
million.

   Long-term fuel supply contracts contain clauses that provide
for periodic price adjustments.  The retail jurisdictions have fuel
clause mechanisms that provide for recovery of changes in the cost
of fuel with the regulators' review and approval.  See Note 4 for
changes in the fuel clause mechanism in the Indiana jurisdiction
proposed in a settlement agreement.  The contracts are for various
terms, the longest of which extends to 2014, and contain various
clauses that would release the Company from its obligation under
certain force majeure conditions.

   The Company is committed under unit power agreements to
purchase all of an affiliate's share, 50% of the 2,600 mw  Rockport
Plant capacity, unless it is sold to other utilities.  The
affiliate has a long-term unit power agreement for the sale of 455
mw to an unaffiliated utility.  Revenues received under this
agreement (which expires at the end of 1999) were $70 million in
1998.  An agreement between the affiliate which owns Rockport Plant
and another affiliate provides for the sales of 390 mw of capacity
to that affiliate through 2004.

   The Company sells under contract up to 250 mw of its Rockport
Plant capacity to an unaffiliated utility.  The contract expires in
2009.

Nuclear Plant

   I&M owns and operates the two-unit 2,110 mw Cook Plant under
licenses granted by the Nuclear Regulatory Commission (NRC).  The
operation of a nuclear facility involves special risks, potential
liabilities, and specific regulatory and safety requirements. 
Should a nuclear incident occur at any nuclear power plant facility
in the United States (US), the resultant liability could be
substantial.  By agreement I&M is partially liable together with
all other electric utility companies that own nuclear generating
units for a nuclear power plant incident.  In the event nuclear
losses or liabilities are underinsured or exceed accumulated funds
and recovery in rates is not possible, results of operations, cash
flows and financial condition would be negatively affected.

Nuclear Plant Shutdown

   I&M shut down both units of the Cook Plant in September 1997
due to questions, which arose during a NRC architect engineer
design inspection, regarding the operability of certain safety
systems.  The NRC issued a Confirmatory Action Letter in September
1997 requiring I&M to address the issues identified in the letter. 
I&M is working with the NRC to resolve the remaining open issue in
the letter.

   In April 1998 the NRC notified I&M that it had convened a
Restart Panel for Cook Plant.  A list of required restart
activities was provided by the NRC in July 1998 and in October the
NRC expanded the list.  In order to identify and resolve the issues
necessary to restart the Cook units, I&M is and will be meeting
with the Panel on a regular basis, until the units are returned to
service.

   In January 1999 I&M announced that it will conduct additional
engineering reviews at the Cook Plant that will delay restart of
the units.  Previously, the units were scheduled to return to
service at the end of the first and second quarters of 1999.  The
decision to delay restart resulted from internal assessments that
indicated a need to conduct expanded system readiness reviews.  A
new restart schedule will be developed based on the results of the
expanded reviews and should be available in June 1999.  When
maintenance and other activities required for restart are complete,
I&M will seek concurrence from the NRC to return the Cook Plant to
service.  Until these additional reviews are completed, management
is unable to determine when the units will be returned to service.
Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect
on results of operations, cash flows and possibly financial
condition.

   The costs incurred in 1997 and 1998 for restart of the Cook
units were $6 million and $78 million, respectively, and were
recorded as operation and maintenance expense.  Reductions in other
operation and maintenance expenses partially offset these costs. 
Currently incremental restart expenses are approximately $12
million a month.

   In July 1998 I&M received an "adverse trend letter" from the
NRC indicating that NRC senior managers determined that there had
been a slow decline in performance at the Cook Plant during the 18
month period preceding the letter.  The letter indicated that the
NRC will closely monitor efforts to address issues at Cook Plant
through additional inspection activities.  In October 1998 the NRC
issued I&M a Notice of Violation and proposed a $500,000 civil
penalty for alleged violations at the Cook Plant discovered during
five inspections conducted between August 1997 and April 1998. I&M
paid the penalty.

   The cost of electricity supplied to certain retail customers
rose due to the extended outage since higher cost coal-fired
generation and coal based purchased power were substituted for low
cost nuclear generation.  I&M's Indiana and Michigan retail
jurisdictional fuel cost recovery mechanisms permit the recovery,
subject to regulatory commission review and approval, of changes in
fuel costs including the fuel component of purchased power in the
Indiana jurisdiction and changes in replacement power in the
Michigan jurisdiction.  The IURC approved, subject to future
reconciliation or refund, agreements authorizing I&M, during the
billing months of July 1998 through March 1999, to include in rates
a fuel cost adjustment factor less than that requested by I&M.  The
agreements provide the parties to the proceedings with the
opportunity to conduct discovery regarding certain issues that were
raised in the proceedings, including the appropriateness of the
recovery of replacement energy cost due to the extended Cook Plant
outage, in anticipation of resolving the issues in a future fuel
cost adjustment proceeding.  A regulatory asset in the amount of
$65 million of replacement energy costs has been recorded at
December 31, 1998.  See Note 4 for discussion of proposed
settlement agreement for the Indiana jurisdiction.

   Historically, the Company has been permitted to recover through
the fuel recovery mechanism the cost of replacement energy during
outages.  Management believes that it should be allowed to recover
the deferred Cook replacement energy costs; however, if recovery of
the replacement costs is denied, future results of operations and
cash flows would be adversely affected by the writeoff of the
regulatory asset.

Nuclear Incident Liability

   Public liability is limited by law to $9 billion should an
incident occur at any licensed reactor in the US.  Commercially
available insurance provides $200 million of coverage.  In the
event of a nuclear incident at any nuclear plant in the US the
remainder of the liability would be provided by a deferred premium
assessment of $88 million on each licensed reactor payable in
annual installments of $10 million.  As a result, I&M could be
assessed $176 million per nuclear incident payable in annual
installments of $20 million.  The number of incidents for which
payments could be required is not limited.

   Nuclear insurance pools and other insurance policies provide $3
billion of property damage, decommissioning and decontamination
coverage for Cook Plant.  Additional insurance provides coverage
for extra costs resulting from a prolonged accidental Cook Plant
outage.  Some of the policies have deferred premium provisions
which could be triggered by losses in excess of the insurer's
resources.  The losses could result from claims at the Cook Plant
or certain other unaffiliated nuclear units.  The Company could be
assessed up to $23.2 million annually under these policies.

SNF Disposal

   Federal law provides for government responsibility for
permanent SNF disposal and assesses nuclear plant owners fees for
SNF disposal.  A fee of one mill per kilowatthour for fuel consumed
after April 6, 1983 is being collected from customers and remitted
to the US Treasury.  Fees and related interest of $190 million for
fuel consumed prior to April 7, 1983 have been recorded as long-term 
debt.  I&M has not paid the government the pre-April 1983 fees
due to continued delays and uncertainties related to the federal
disposal program.  At December 31, 1998, funds collected from
customers towards payment of the pre-April 1983 fee and related
earnings thereon approximate the liability.

Decommissioning and Low Level Waste Accumulation Disposal

   Decommissioning costs are being accrued over the service life
of the Cook Plant.  The licenses to operate the two nuclear units
expire in 2014 and 2017.  After expiration of the licenses the
plant is expected to be decommissioned through dismantlement.  The
estimated cost of decommissioning and low level radioactive waste
accumulation disposal costs ranges from $700 million to $1,152
million in 1997 nondiscounted dollars.  The wide range is caused by
variables in assumptions including the estimated length of time SNF
may need to be stored at the plant site subsequent to ceasing
operations.  This, in turn, depends on future developments in the
federal government's SNF disposal program.  Continued delays in the
federal fuel disposal program can result in increased
decommissioning costs.  The Company is recovering estimated
decommissioning costs in its three rate-making jurisdictions based
on at least the lower end of the range in the most recent
decommissioning study at the time of the last rate proceeding.  The
Company records decommissioning costs in other operation expense
and records a noncurrent liability equal to the decommissioning
cost recovered in rates; such amount was $29 million in 1998, $28
million in 1997 and $27 million in 1996.  Decommissioning costs
recovered from customers are deposited in external trusts, which
are described in Note 7.  Trust fund earnings increase the fund
assets and the recorded liability and decrease the amount needed to
be recovered from ratepayers.  During 1998 the Company withdrew $3
million from the trust funds and expects to withdraw $8 million in
1999 for decommissioning the original steam generators removed from
Unit 2.  At December 31, 1998 and 1997, the Company has recognized
a decommissioning liability of $446 million and $381 million,
respectively.

Air Quality

   On September 24, 1998, the US Environmental Protection Agency
(Federal EPA) finalized rules which require reductions in nitrogen
oxides (NOx) emissions in 22 eastern states, including the states
in which the generating plants of the Company and its AEP Power
Pool affiliates are located.  The implementation of the final rules
would be achieved through the revision of state implementation
plans (SIPs) by September 1999.  SIPs are a procedural method used
by each state to comply with Federal EPA rules.  The final rules
anticipate the imposition of a NOx reduction on utility sources of
approximately 85% below 1990 emission levels by the year 2003.  On
October 30, 1998, a number of utilities, including the Company and
the other operating companies of the AEP System, filed petitions in
the US Court of Appeals for the District of Columbia Circuit
seeking a review of the final rules.

   Should the states fail to adopt the required revisions to their
SIPs within one year of the date of the final rules (September 24,
1999), Federal EPA has proposed to implement a federal plan to
accomplish the NOx reductions.  Federal EPA also proposed the
approval of portions of petitions filed by eight northeastern
states that would result in imposition of NOx emission reductions
on utility and industrial sources in upwind midwestern states. 
These reductions are substantially the same as those required by
the final NOx rules and could be adopted by Federal EPA in the
event the states fail to implement SIPs in accordance with the
final rules.

   Preliminary estimates indicate that compliance could result in
required capital expenditures of approximately $169 million. 
Compliance costs cannot be estimated with certainty and the actual
costs incurred to comply could be significantly different from this
preliminary estimate depending upon the compliance alternatives
selected to achieve reductions in NOx emissions.  Unless such costs
are recovered from customers, they would have a material adverse
effect on results of operations, cash flows and possibly financial
condition.

Litigation

   The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns for the years 1991
to 1993 requested a ruling from their National Office that certain
interest deductions claimed by the Company relating to a corporate
owned life insurance (COLI) program should not be allowed.  As a
result of a suit filed by the Company in US District Court
(discussed below) the request for ruling was withdrawn by the IRS
agents.  Adjustments have been or will be proposed by the IRS
disallowing COLI interest deductions for taxable years 1991-96.  A
disallowance of the COLI interest deductions through December 31,
1998 would reduce earnings by approximately $66 million (including
interest).  The Company has made no provision for any possible
adverse earnings impact from this matter.

   In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991-97
to avoid the potential assessment by the IRS of any additional
above market rate interest on the contested amount.  The payments 
to the IRS are included on the balance sheet in other property and
investments pending the resolution of this matter.  The Company
will seek refund, either administratively or through litigation, of
all amounts paid plus interest.  In order to resolve this issue
without further delay, on March 24, 1998, the Company filed suit
against the US in the US District Court for the Southern District
of Ohio.  Management believes that it has a meritorious position
and will vigorously pursue this lawsuit.  In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.

   The Company is involved in a number of other legal proceedings
and claims.  While management is unable to predict the ultimate
outcome of litigation, it is not expected that the resolution of
these matters will have a material adverse effect on the results of
operations, cash flows and financial condition.


4. SUBSEQUENT EVENT - SETTLEMENT AGREEMENT (MARCH 16, 1999):

   On March 16, 1999 a settlement agreement was filed with the
IURC resolving all matters related to the reasonableness of fuel
costs and all outage issues during an extended outage of the Cook
Plant.  The settlement agreement, which is subject to IURC
approval, provides for, among other things, a credit of $55 million
to Indiana retail customers; authorization to defer any unrecovered
fuel revenues accrued between September 9, 1997 and December 31,
1999 including the $55 million; authorization to defer up to $150
million of incremental operation and maintenance restart costs for
the Cook Plant above the base rate level incurred during 1999;
amortization of the fuel recoveries and restart cost deferrals over
a five-year period ending December 31, 2003; a freeze in base rates
though December 31, 2003; and a cap on fuel recovery charges
through March 1, 2004.  The $55 million credit will be refunded
through customer's bills  during the months of July, August and
September 1999.  If the IURC does not approve the settlement, the
issue of recovery of replacement energy costs would be resolved
through  regulatory hearings.  Unless the costs of the extended
outage and restart efforts are recovered from customers, there
would be a material adverse effect on results of operations, cash
flows, and possibly financial condition.


5. RELATED PARTY TRANSACTIONS:

   Benefits and costs of the AEP System's generating plants are
shared by members of the AEP Power Pool of which the Company is a
member.  Under the terms of the AEP System Interconnection
Agreement, capacity charges and credits are designed to allocate
the cost of the AEP System's capacity among the AEP Power Pool
members based on their relative peak demands and generating
reserves.  AEP Power Pool members are also compensated for the 
out-of-pocket costs of energy delivered to the AEP Power Pool and
charged for energy received from the AEP Power Pool.  The Company
is a net supplier to the AEP Power Pool and, therefore, receives
capacity credits from the AEP Power Pool.

<PAGE>
   Operating revenues include revenues for capacity and energy
supplied to the AEP Power Pool as follows:

                            Year Ended December 31,    
                          1998        1997       1996
                                 (in thousands)

Capacity Revenues        $33,011    $ 53,282   $ 57,594
Energy Revenues            4,550      64,861     98,162

     Total               $37,561    $118,143   $155,756



   Purchased power expense includes charges of $125.2 million in
1998, $51 million in 1997 and $34.5 million in 1996 for energy
received from the AEP Power Pool.


   Power marketing and trading operations, which are described in
Note 1, are conducted by the AEP Power Pool and shared with the
Company.  The Company's operating revenues, purchased power expense
and nonoperating income include amounts for power marketing and
trading allocated by the AEP Power Pool as follows:

                             Year Ended December 31,  
                            1998       1997      1996
                                  (in thousands)
Operating Revenues        $124,973   $74,895   $73,424
Purchased Power Expense     71,588    15,415     8,098
Nonoperating Loss           (7,122)      (61)     -

   The cost of Rockport Plant power purchased from AEGCo, an
affiliated company that is not a member of the AEP Power Pool, was
included in purchased power expense in the amounts of $86.2
million, $87.5 million and $85.4 million in 1998, 1997 and 1996,
respectively.

   The cost of power purchased from Ohio Valley Electric
Corporation, an affiliated company that is not  a member  of  the 
AEP Power Pool, was included in purchased power expense in the
amounts of $14.3 million, $11 million and $10.7 million in 1998,
1997 and 1996, respectively.

   The Company operates the Rockport Plant and bills AEGCo for its
share of operating costs.

   AEP System companies participate in the AEP System Transmission
Equalization Agreement.  This agreement combines certain AEP System
companies' investments in transmission facilities and shares the
costs of ownership in proportion to the AEP System companies'
respective peak demands.  Pursuant to the terms of the agreement,
since the Company's relative investment in transmission facilities
is greater than its relative peak demand, other operation expense
includes equalization credits of $44.1 million, $46.1 million and
$46.3 million in 1998, 1997 and 1996, respectively.

   Revenues from providing barging services were recorded in
nonoperating income as follows:

                            Year Ended December 31,   
                          1998        1997       1996
                                 (in thousands)

Affiliated Companies    $23,494     $24,427    $22,740
Unaffiliated Companies   12,490       8,383      6,776
     Total              $35,984     $32,810    $29,516

   American Electric Power Service Corporation (AEPSC) provides
certain managerial and professional services to AEP System
companies including the Company.  The costs of the services are
billed by AEPSC to its affiliated clients on a direct-charge basis
whenever possible and on reasonable bases of proration for shared
services.  The billing for services are made at cost and include no
compensation for the use of equity capital, which is furnished to
AEPSC by AEP Co., Inc.  Billings from AEPSC are capitalized or
expensed depending on the nature of the services rendered.  AEPSC
and its billings are subject to the regulation of the SEC under the
1935 Act.


6. SEGMENT INFORMATION:

   Effective December 31, 1998 the Company adopted SFAS 131,
"Disclosures about Segments of an Enterprise and Related
Information".  The Company has one reportable segment, a regulated
vertically integrated electricity generation and energy delivery
business.  All other activities are insignificant.  The Company's
operations are managed on an integrated basis because of the
substantial impact of bundled cost-based rates and regulatory
oversight on business processes, cost structures and operating
results.  Aggregated in the regulated electric utility segment is
the power marketing and trading activities that are discussed in
Note 1 and the Company's barging activities.  For the years ended
December 31, 1998, 1997 and 1996, all revenues are derived in the
US.


7. FINANCIAL INSTRUMENTS, CREDIT AND RISK MANAGEMENT:

   The Company is subject to market risk as a result of changes in
electricity commodity prices and interest rates.  The Company
participates in the AEP Power Pool's power marketing and trading
operation that manages the exposure to electricity commodity price
movements using physical forward purchase and sale contracts at
fixed and variable prices, and financial derivative instruments
including exchange traded futures and options, over-the-counter
options, swaps and other financial derivative contracts at both
fixed and variable prices.  Physical forward electricity contracts
within the AEP Power Pool's traditional marketing area are recorded
on a net basis as operating revenues in the month when the physical
contract settles.  The Company's share of the net gains from these
regulated transactions for the year ended December 31, 1998 was $21
million.  Physical forward electricity contracts outside the AEP
Power Pool's traditional marketing area and all financial
electricity trading transactions including exchange traded
contracts that are marked to market and recorded in nonoperating
income.  The Company's share of the net losses from these non-regulated 
trading transactions for the year ended December 31, 1998
was $7 million.  The unrealized mark-to-market gains and losses
from such trading of financial instruments are reported as assets
and liabilities, respectively.  These activities were not material
in prior periods.

   The Company is exposed to risk from changes in interest rates
primarily due to short-term and long-term borrowings used to fund
its business operations.  The debt portfolio has both fixed and
variable interest rates with terms from one day to forty years and
an average duration of six years at December 31, 1998.  A near term
change in interest rates should not materially affect results of
operations or financial position since the Company would not expect
to liquidate its entire debt portfolio in a one year holding
period.  Also since the Company's rates are cost-based regulated,
the risk of interest rate changes on debt used to finance regulated
operations is mitigated.

Market Valuation

   The book value of cash and cash equivalents, accounts
receivable, short-term debt and accounts payable approximate fair
value because of the short-term maturity of these instruments.  The
book value of the pre-April 1983 spent nuclear fuel disposal
liability approximates the Company's best estimate of its fair
value.

   The book value amounts and fair values of the Company's share
of significant financial instruments at December 31, 1998 and 1997
are summarized in the following table.  The fair values of long-term 
debt and preferred stock are based on quoted market prices for
the same or similar issues and the current dividend or interest
rates offered for instruments of the same remaining maturities. 
The fair value of those financial instruments that are marked-to-market 
are based on management's best estimates using over-the-counter quotations, 
exchange prices, volatility factors and
valuation methodology.  The estimates presented herein are not
necessarily indicative of the amounts that the Company could
realize in a current market exchange.  At December 31, 1997 the
notional amounts and fair values of derivatives were not material.
<PAGE>
                       Book Value  Fair Value
                           (in thousands)
Non-Derivatives

1998

Long-term Debt        $1,175,800   $1,235,200

Preferred Stock           68,400       72,600

1997

Long-term Debt         1,049,200    1,094,100

Preferred Stock           68,400       73,300

Derivatives

1998 

                       Fair Value  Average Fair Value
                               (in thousands)
Trading Assets

Electric
  Physicals               $8,700       $ 7,700
  Options                  6,300        15,300
  Swaps                      600           200

Trading Liabilities

Electric
  Futures                 (1,300)         (300)
  Physicals               (9,400)       (8,800)
  Options                 (5,700)      (15,200)
  Swaps                   (1,400)         (400)

   At December 31, 1998 the notional amounts of the Company's
nonregulated electric trading physical forward contract purchases
and sales are 1,912 Gigawatt hours (Gwh) and 2,044 Gwh,
respectively; the notional amounts for fixed priced swaps purchases
and sales are 70 Gwh and 75 Gwh, respectively; and the notional
amounts for options to purchase and to sell are 1,381 Gwh and 992
Gwh, respectively.  The Company has a net long position of 74 Gwh
for electric future contracts.

   At December 31, 1998 the fair value of the assets and
liabilities related to the wholesale electric forward contracts was
$69 million and $67 million, respectively.  The related notional
amounts were 9,094 Gwh for purchases and 9,280 Gwh for sales.  The
average fair value amounts outstanding during the period were $175
million of assets and $167 million of liabilities.

Credit and Risk Management

   In addition to market risk associated with price movements, the
Company through the AEP Power Pool is also subject to the credit
risk inherent in its risk management activities.  Credit risk
refers to the financial risk arising from commercial transactions
and/or the intrinsic financial value of contractual agreements with
trading counter parties, by which there exists a potential risk of
nonperformance.  The AEP Power Pool has established and enforced
credit policies that minimize this risk.  The AEP Power Pool
accepts as counter parties to forwards, futures, and other
derivative contracts primarily those entities that are classified
as Investment Grade, or those that can be considered as such due to
the effective placement of credit enhancements and/or collateral
agreements.  Investment grade is the designation given to the four
highest debt rating categories (i.e., AAA, AA, A, BBB) of the major
rating services, e.g., ratings BBB- and above at Standard & Poor's
and Baa3 and above at Moody's.  When adverse market conditions have
the potential to negatively affect a counter party's credit
position, the AEP Power Pool requires further credit enhancements
to mitigate risk.  Since the formation of the power marketing and
trading business in July of 1997, the Company has experienced no
significant losses due to the credit risk associated with risk
management activities; furthermore, the Company does not anticipate
any future material effect on its results of operations, cash flow
or financial condition as a result of counter party nonperformance.

Nuclear Trust Funds Recorded at Market Value

   The Nuclear Decommissioning and Spent Nuclear Fuel Disposal
Trust Fund investments are recorded at market value in accordance
with SFAS 115 and consist of tax-exempt municipal bonds and other
securities.

   At December 31, 1998 and 1997 the fair values of trust fund
investments were $648 million and $566 million, respectively. 
Accumulated gross unrealized holding gains were $65 million and $41
million and accumulated gross unrealized holding losses were $1.1
million and $1.2 million at December 31, 1998 and 1997,
respectively.  The change in market value in 1998, 1997 and 1996
was a net unrealized holding gain of $24 million, $19.1 million and
$2.6 million, respectively.

   The trust fund investments' cost basis by security type were:

                                   December 31,      
                               1998            1997
                                  (in thousands)
  Tax-Exempt Bonds           $326,239        $335,358
  Equity Securities            95,854          74,398
  Treasury Bonds               71,194          44,200
  Corporate Bonds              10,661           9,167
  Cash, Cash Equivalents
   and Interest Accrued        80,065          63,392
    Total                    $584,013        $526,515

   Proceeds from sales and maturities of securities of $225
million during 1998 resulted in $8.2 million of realized gains and
$2.8 million of realized losses.  Proceeds from sales and
maturities of securities of $147.3 million during 1997 resulted in
$3.9 million of realized gains and $1.4 million of realized losses. 
Proceeds from sales and maturities of securities of $115.3 million
during 1996 resulted in $2.6 million of realized gains and $2.1
million of realized losses.  The cost of securities for determining
realized gains and losses is original acquisition cost including
amortized premiums and discounts.

   At December 31, 1998, the year of maturity of trust fund
investments, other than equity securities, was:

                               (in thousands)

        1999                      $106,316
        2000-2003                  157,224
        2004-2008                  175,751
        After 2008                  48,868
          Total                   $488,159


8. STAFF REDUCTIONS:

   During 1998 an internal evaluation of the power generation
organization was conducted with a goal of developing a better
organizational structure for a competitive generation market.  The
study was completed in October 1998.  In addition, a review of
energy delivery staffing levels was conducted in 1998.  As a result
approximately 80 power generation and energy delivery positions
were identified for elimination.

   Severance accruals totaling $3.7 million were recorded in
December 1998 for reductions in power generation and energy
delivery staffs and were charged to other operation expense in the
Consolidated Statements of Income.  In the first quarter of 1999
the power generation and energy delivery staff reductions were
made.


9. BENEFIT PLANS:

   The Company and its subsidiaries participate in the AEP System
qualified pension plan, a defined benefit plan which covers all
employees.  Net pension costs for the years ended December 31,
1998, 1997 and 1996 were $2.1 million, $2.1 million and $4.1
million, respectively.

   Postretirement benefits other than pensions are provided for
retired employees for medical and death benefits under an AEP
System plan.  The Company's annual accrued costs for 1998, 1997 and
1996 were $12 million, $11.5 million and $12.8 million,
respectively.

   A defined contribution employee savings plan required that the
Company make contributions to the plan totaling $4 million in 1998
and 1997 and $3.7 million in 1996.

</TABLE>
<TABLE>
<PAGE>
10. FEDERAL INCOME TAXES:

   The details of federal income taxes as reported are as follows:
<CAPTION>
                                                                      Year Ended December 31,               
                                                         1998                  1997                  1996
                                                                          (in thousands)
<S>                                                    <C>                   <C>                   <C>
Charged (Credited) to Operating Expenses (net):
  Current                                              $ 38,165              $ 75,442              $110,133
  Deferred                                               21,073                 3,088               (24,730)
  Deferred Investment Tax Credits                        (7,593)               (7,786)               (7,874)
        Total                                            51,645                70,744                77,529 
Charged (Credited) to Nonoperating Income (net):
  Current                                                  (594)                3,287                   182 
  Deferred                                               (3,168)                  834                    43 
  Deferred Investment Tax Credits                          (673)                 (642)                 (855)
        Total                                            (4,435)                3,479                  (630)
Total Federal Income Taxes as Reported                 $ 47,210              $ 74,223              $ 76,899 

  The following is a reconciliation of the difference between the
amount of federal income taxes computed by multiplying book income
before federal income taxes by the statutory tax rate, and the
amount of federal income taxes reported.

                                                                      Year Ended December 31,               
                                                         1998                  1997                  1996
                                                                          (in thousands)

Net Income                                             $ 96,628              $146,740              $157,153 
Federal Income Taxes                                     47,210                74,223                76,899 
Pre-tax Book Income                                    $143,838              $220,963              $234,052 

Federal Income Tax on Pre-tax Book Income at 
  Statutory Rate (35%)                                  $50,343               $77,337               $81,918 
Increase (Decrease) in Federal Income Tax
  Resulting From the Following Items:
    Depreciation                                         17,257                14,082                13,880 
    Corporate Owned Life Insurance                       (3,263)               (3,348)               (2,178)
    Nuclear Fuel Disposal Costs                          (3,397)               (3,286)               (3,096)
    Investment Tax Credits (net)                         (8,266)               (8,428)               (8,729)
    Other                                                (5,464)               (2,134)               (4,896)
Total Federal Income Taxes as Reported                  $47,210               $74,223               $76,899 

Effective Federal Income Tax Rate                          32.8%                 33.6%                 32.9%
</TABLE>

<PAGE>
   The following tables show the elements of the net deferred tax
liability and the significant temporary differences giving rise to
such deferrals:
                                    December 31,    
                                  1998        1997
                                   (in thousands)

Deferred Tax Assets            $ 226,118   $ 223,772
Deferred Tax Liabilities        (785,406)   (783,480)
  Net Deferred Tax Liabilities $(559,288)  $(559,708)

Property Related 
 Temporary Differences         $(460,077)  $(471,898)
Amounts Due From Customers
  For Future Federal 
  Income Taxes                   (69,102)    (74,282)
Deferred State Income Taxes      (62,302)    (65,679)
Deferred Gain on Sale and
  Leaseback of Rockport 
  Plant Unit 2                    31,049      32,347 
Accrued Nuclear
  Decommissioning Expense         29,930      26,991
All Other (net)                  (28,786)     (7,187)
  Net Deferred Tax Liabilities $(559,288)  $(559,708)

   The Company and its subsidiaries join in the filing of a
consolidated federal income tax return with their affiliates in the
AEP System.  The allocation of the AEP System's current
consolidated federal income tax to the AEP System companies is in
accordance with SEC rules under the 1935 Act.  These rules permit
the allocation of the benefit of current tax losses to the System
companies giving rise to them in determining their current tax
expense.  The tax loss of the parent company, AEP Co., Inc., is
allocated to its subsidiaries with taxable income.  With the
exception of the loss of the parent company, the method of
allocation approximates a separate return result for each company
in the consolidated group.

   The AEP System has settled with the IRS all issues from the
audits of the consolidated federal income tax returns for the years
prior to 1991.  Returns for the years 1991 through 1996 are
presently being audited by the IRS.  With the exception of interest
deductions related to COLI, which are discussed under the heading,
Litigation, in Note 3, management is not aware of any issues for
open tax years that upon final resolution are expected to have a
material adverse effect on results of operations.


12. COMMON SHAREHOLDER'S EQUITY:

   Mortgage indentures, charter provisions and orders of
regulatory authorities place various restrictions on the use of
retained earnings for the payment of cash dividends on common
stock.  At December 31, 1998, $5.9 million of retained earnings
were restricted.  Regulatory approval is required to pay dividends
out of paid-in capital.

   In 1998, 1997 and 1996 net changes to paid-in capital of
$133,000, $1,200,000 and $170,000 respectively, represented gains
and expenses associated with cumulative preferred stock
transactions.


12. SUPPLEMENTARY INFORMATION:

                                Year Ended December 31,   
                             1998        1997       1996
                                    (in thousands)
Cash was paid for:
  Interest (net of 
    capitalized amounts)    $66,313    $ 62,274   $ 64,117
  Income Taxes               36,413     120,212    125,707
Noncash Acquisitions
  Under Capital Leases        9,658     111,395     48,305

   In connection with the 1996 early termination of a western coal
land sublease the Company will receive cash payments from the
lessee of $30.8 million over a ten-year period which was recorded
at a net present value of $22.8 million.  The long-term portion of
this receivable is recorded as other property and investments and
the current portion is recorded as miscellaneous accounts
receivable.

13.  CUMULATIVE PREFERRED STOCK:

     At December 31, 1998, authorized shares of cumulative
preferred stock were as follows:

               Par Value                     Shares Authorized
                 $100                             2,250,000
                   25                            11,200,000

  The cumulative preferred stock is callable at the price
indicated below plus accrued dividends.  The involuntary
liquidation preference is par value.  Unissued shares of the
cumulative preferred stock may or may not possess mandatory
redemption characteristics upon issuance.  During 1996 the Company
redeemed and canceled 300,000 shares of the 7.08% series not
subject to mandatory redemption.

A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
<TABLE>
<CAPTION>
         Call Price                                                 Shares            Amount     
         December 31,  Par      Number of Shares Redeemed         Outstanding      December 31,  
 Series      1998     Value      Year Ended December 31,       December 31, 1998  1998      1997
                               1998       1997        1996                         (in thousands)
<S>       <C>         <C>       <C>     <C>            <C>          <C>          <C>       <C> 
4-1/8%    $106.125    $100      771     59,760         233          59,236       $5,924    $6,001
4.56%      102         100      650     44,788         -            14,562        1,456     1,521
4.12%      102.728     100      200     20,869         -            18,931        1,893     1,913
                                                                                 $9,273    $9,435

B. Cumulative Preferred Stock Subject to Mandatory Redemption:

                                                                    Shares            Amount     
                       Par      Number of Shares Redeemed         Outstanding      December 31,  
 Series(a)            Value      Year Ended December 31,       December 31, 1998  1998      1997
                              1998       1997        1996                         (in thousands)

5.90% (b)             $100      -      233,000         -           167,000      $16,700   $16,700
6-1/4%(b)              100      -       97,500         -           202,500       20,250    20,250
6.30% (b)              100      -      217,550         -           132,450       13,245    13,245
6-7/8%(c)              100      -      117,500         -           182,500       18,250    18,250
                                                                                $68,445   $68,445
</TABLE>
(a) Not callable until after 2002.  There are no aggregate sinking
fund provisions through 2002.  A  sinking fund provision requires
the redemption of 15,000 shares in 2003.
(b) Commencing in 2004 and continuing through 2008 the Company may
redeem, at $100 per share, 20,000 shares of the 5.90% series,
15,000 shares of the 6-1/4% series and 17,500 shares of the 6.30%
series outstanding under sinking fund provisions at its option and
all remaining outstanding shares must be redeemed not later than
2009.  Shares redeemed in 1997 may be applied to meet the sinking
fund requirement.

(c) Commencing in 2003 and continuing through the year 2007, a
sinking fund will require the redemption of 15,000 shares each year
and the redemption of the remaining shares outstanding on April 1,
2008, in each case at $100 per share.  Shares redeemed in 1997 may
be applied to meet the sinking fund requirement.


14.  LONG-TERM DEBT AND LINES OF CREDIT:

  Long-term debt by major category was outstanding as follows:

                                   December 31,     
                               1998           1997
                                 (in thousands)

First Mortgage Bonds        $  466,330     $  520,317
Installment Purchase 
  Contracts                    309,418        309,269
Senior Unsecured Notes          48,559           -
Other Long-term Debt (a)       190,192        180,837
Junior Debentures              161,290         38,814
                             1,175,789      1,049,237
Less Portion Due Within
  One Year                      35,000         35,000

  Total                     $1,140,789     $1,014,237

(a)    Represents a SNF disposal liability including interest accrued
payable to the Department of Energy.  See Note 3.

<PAGE>
  First mortgage bonds outstanding were as follows:

                                     December 31,   
                                   1998       1997
                                    (in thousands)
% Rate Due                 
7.00    1998 - May 1             $    -     $ 35,000
7.30    1999 - December 15         35,000     35,000
6.40    2000 - March 1             48,000     48,000
7.63    2001 - June 1              40,000     40,000
7.60    2002 - November 1          50,000     50,000
7.70    2002 - December 15         40,000     40,000
6.80    2003 - July 1              20,000     20,000
6.55    2003 - October 1           20,000     20,000
6.10    2003 - November 1          30,000     30,000
6.55    2004 - March 1             25,000     25,000
8.50    2022 - December 15         75,000     75,000
7.80    2023 - July 1                 -       20,000
7.35    2023 - October 1           20,000     20,000
7.20    2024 - February 1          40,000     40,000
7.50    2024 - March 1             25,000     25,000
Unamortized Discount (net)         (1,670)    (2,683)
                                  466,330    520,317
Less Portion Due Within One Year   35,000     35,000
  Total                          $431,330   $485,317

  Certain indentures relating to the first mortgage bonds
contain improvement, maintenance and replacement provisions
requiring the deposit of cash or bonds with the trustee, or in lieu
thereof, certification of unfunded property additions.

  Installment purchase contracts have been entered into in
connection with the issuance of pollution control revenue bonds by
governmental authorities as follows:

                                     December 31,    
                                   1998        1997
                                    (in thousands)
% Rate  Due                    
City of Lawrenceburg, Indiana:
7.00    2015 - April 1           $ 25,000    $ 25,000
5.90    2019 - November 1          52,000      52,000
City of Rockport, Indiana:
(a)     2014 - August 1            50,000      50,000
7.60    2016 - March 1             40,000      40,000
6.55    2025 - June 1              50,000      50,000
(b)     2025 - June 1              50,000      50,000
City of Sullivan, Indiana:
5.95    2009 - May 1               45,000      45,000
Unamortized Discount               (2,582)     (2,731)

  Total                          $309,418    $309,269

<PAGE>
(a)    A variable interest rate is determined weekly.  The average
       weighted interest rate was 4.1% for 1998 and 4.3% for 1997.
(b)    An adjustable interest rate can be a daily, weekly, commercial
       paper or term rate as designated by the Company.  A weekly
       rate was selected which ranged from 2.7% to 4.3% in 1998 and
       from 3.0% to 4.6% in 1997 and averaged 3.6% and 3.8% during
       1998 and 1997, respectively.

  Under the terms of certain installment purchase contracts, the
Company is required to pay amounts sufficient to enable the cities
to pay interest on and the principal (at stated maturities and upon
mandatory redemption) of related pollution control revenue bonds
issued to finance the construction of pollution control facilities
at certain generating plants.  On the two variable rate series the
principal is payable at the stated maturities or on the demand of
the bondholders at periodic interest adjustment dates which occur
weekly.  The variable rate bonds due in 2014 are supported by a
bank letter of credit which expires in 2002.  I&M has agreements
that provide for brokers to remarket the adjustable rate bonds due
in 2025 tendered at interest adjustment dates.  In the event
certain bonds cannot be remarketed, I&M has a standby  bond 
purchase  agreement with a bank that provides for the bank to
purchase any bonds not remarketed.  The purchase agreement expires
in 2000.  Accordingly, the variable and adjustable rate installment
purchase contracts have been classified for repayment purposes
based on the expiration dates of the standby purchase agreement and
the letter of credit.

  In November 1998 the Company issued $50,000,000 of 6.45%
senior unsecured notes due November 10, 2008.  The unamortized
discount at December 31, 1998 was $1,441,000.

  Junior debentures are composed of the following:

                                          December 31,    
                                        1998        1997
                                         (in thousands)
% Rate Due                
8.00   2026 - March 31               $ 40,000      $40,000
7.60   2038 - June 30                 125,000          -
Unamortized Discount                   (3,710)      (1,186)
  Total                              $161,290      $38,814

  Interest may be deferred and payment of principal and interest
on the junior debentures is subordinated and subject in right to
the prior payment in full of all senior indebtedness of the
Company.

<PAGE>
  At December 31, 1998, future annual long-term debt payments
are as follows:
                                       Amount
                                   (in thousands) 

  1999                               $   35,000
  2000                                   98,000
  2001                                   40,000 
  2002                                  140,000 
  2003                                   70,000
  Later Years                           802,192   
    Total Principal Amount            1,185,192   
  Unamortized Discount                   (9,403)
      Total                          $1,175,789

  Short-term debt borrowings are limited by provisions of the
1935 Act to $300 million.  Lines of credit are shared with AEP
System companies and at December 31, 1998 and 1997 were available
in the amounts of $763 million and $442 million, respectively. 
Facility fees of approximately 1/10 of 1% of the short-term lines
of credit are required by the banks to maintain the lines of
credit.

Outstanding short-term debt consisted of:
                                          Year-end
                            Balance       Weighted
                          Outstanding      Average
                        (in thousands)  Interest Rate
December 31, 1998:
  Commercial Paper         $108,700         6.2%

December 31, 1997:
  Notes Payable            $ 56,410         6.3%
  Commercial Paper           63,190         6.8
    Total                  $119,600         6.6


15. LEASES:

  Leases of property, plant and equipment are for periods of
up to 35 years and require payments of related property taxes,
maintenance and operating costs.  The Company is leasing 50% of
the 1,300 mw Rockport 2 generating unit under an operating lease. 
The lease has 24 years remaining and total minimum lease payments
of $1.8 billion.  The majority of the leases have purchase or
renewal options and will be renewed or replaced by other leases.

<PAGE>
  Lease rentals for both operating and capital leases are
generally charged to operating expenses in accordance with rate-making 
treatment.  The components of rental costs are as follows:

                                   Year Ended December 31,   
                                 1998       1997       1996
                                       (in thousands)

Lease Payments on 
  Operating Leases             $ 88,297   $ 92,067   $ 96,096
Amortization of Capital Leases   10,717     42,882     55,789
Interest on Capital Leases       10,302      9,737     10,624
      Total Lease Rental Costs $109,316   $144,686   $162,509

  Properties under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:

                                                 December 31,    
                                               1998        1997
                                                (in thousands)
Electric Utility Plant Under Capital Leases:
  Production Plant                           $  8,850    $  9,218
  Distribution Plant                           14,645      14,660
  General Plant:
    Nuclear Fuel (net of amortization)        103,939     103,939
    Other Plant                                60,002      61,268
Total Electric Utility Plant
  Under Capital Leases                        187,436     189,085
  Accumulated Amortization                     33,948      31,358
Net Electric Utility Plant
  Under Capital Leases                        153,488     157,727

Other Property Under Capital Leases            37,672      40,746
Accumulated Amortization                        4,733       3,246
Net Other Property Under Capital Leases        32,939      37,500
Net Properties Under Capital Leases          $186,427    $195,227

Capital Lease Obligations*:
  Noncurrent Liability                       $176,760    $161,194
  Liability Due Within One Year                 9,667      34,033
Total Capital Lease Obligations              $186,427    $195,227

* Represents the present value of future minimum lease payments.

  The noncurrent portion of capital lease obligations is
included in other noncurrent liabilities in the Consolidated
Balance Sheets.  Properties under operating leases and related
obligations are not included in the Consolidated Balance Sheets.

<PAGE>
  Future minimum lease payments consisted of the following at
December 31, 1998:
                                             Non-
                                          Cancelable
                            Capital       Operating
                            Leases          Leases   
                               (in thousands)

  1999                    $ 15,807      $   98,992
  2000                      14,371          98,729
  2001                      12,524          97,494
  2002                      18,521          95,778
  2003                       9,141          95,685
  Later Years               38,505       1,608,787 

  Total Future Minimum 
    Lease Payments         108,869(a)   $2,095,465 

  Less Estimated 
    Interest Element        26,381

  Estimated Present 
   Value of Future 
   Minimum Lease 
   Payments                 82,488
  Unamortized Nuclear 
   Fuel                    103,939
    Total                 $186,427

(a) Excludes nuclear fuel rentals which are paid  in proportion to
heat produced  and  carrying  charges  on the  unamortized nuclear 
fuel balance.  There  are no  minimum  lease payment requirements
for leased nuclear fuel.


16. UNAUDITED QUARTERLY FINANCIAL INFORMATION:

                                                  Net
Quarterly Periods        Operating  Operating   Income
     Ended                Revenues   Income     (Loss) 
                                   (in thousands)
1998
 March 31                 $328,468   $51,368   $33,744
 June 30                   348,271    42,194    28,536
 September 30              412,908    58,639    38,691
 December 31               316,147    13,806    (4,343)

1997
 March 31                  341,313    59,894    44,259
 June 30                   320,508    50,140    33,908
 September 30              347,668    60,449    45,091
 December 31               329,743    37,305    23,482


Fourth quarter 1998 operating income and net income declined
primarily as a result of expenditures to prepare the nuclear units
for restart.

See "Reclassification" in Note 1 regarding reclassification of
prior period amounts.